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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, 20011
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 28, 2002, there were 10 shares of common stock of Selkirk Cogen
Funding Corporation, $1 par value outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None
TABLE OF CONTENTS
Page
----
PART I
Item 1. Business............................................................. 1
Item 2. Properties........................................................... 14
Item 3. Legal Proceedings.................................................... 15
Item 4. Submission of Matters to a Vote of Security Holders.................. 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters................................................. 17
Item 6. Selected Financial Data.............................................. 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................. 19
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .......... 35
Item 8. Financial Statements and Supplementary Data.......................... 35
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................. 35
PART III
Item 10. Directors and Executive Officers of the Funding Corporation
and the Managing General Partner................................... 36
Item 11. Executive and Board Compensation and Benefits....................... 38
Item 12. Security Ownership of Certain Beneficial Owners and
Management......................................................... 38
Item 13. Certain Relationships and Related Transactions...................... 40
PART IV
Item 14. Financial Statements, Exhibits and Reports on Form 8-K.............. 41
Signatures................................................................... 55
i
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 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.
1
JMC Selkirk is an indirect, wholly-owned subsidiary of Beale Generating
Company ("Beale", formerly J. Makowski Company, Inc.) 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 Merchant Services, Inc. ("Aquila", formerly
Aquila, Inc.).
In December 2000, and in January and February 2001, PG&E Corporation
and NEG completed a corporate restructuring of NEG, known as a
“ringfencing” transaction. The ringfencing involved the use or
creation of limited liability companies (“LLCs”) as intermediate
owners between a parent company and its subsidiaries. One of these LLCs is
PG&E National Energy Group, LLC, which owns 100% of the stock of NEG. After
the ringfencing structure was implemented, two independent rating agencies,
Standard and Poor’s and Moody’s Investor Services issued investment
grade ratings for NEG and reaffirmed such ratings for certain NEG subsidiaries.
On April 6, 2001, Pacific Gas and Electric Company (the “Utility”),
another subsidiary of PG&E Corporation, filed a voluntary petition for
relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant
to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its
assets and is authorized to operate its business as a debtor-in-possession while
being subject to the jurisdiction of the Bankruptcy Court. On September 20,
2001, the Utility and PG&E Corporation jointly filed a plan of
reorganization that entails separating the Utility into four distinct
businesses. The plan of reorganization does not directly affect NEG or any of
its subsidiaries. Subsequent to the bankruptcy filing, the investment grade
ratings of NEG and its rated subsidiaries were reaffirmed on April 6 and 9,
2001. The Managing General Partner believes that NEG and its direct and indirect
subsidiaries as described above, including JMC Selkirk, Investors, or the
Partnership, would not be substantively consolidated with PG&E Corporation
in any insolvency or bankruptcy proceeding involving PG&E Corporation or the
Utility.
2
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.
3
The Facility and Certain Project Contracts
The Facility
The Facility is located on an approximately 15.7 acre site leased from
General Electric adjacent to General Electric’s plastic manufacturing plant
(the “GE Plant”) in the Town of Bethlehem, County of Albany, New York
(the “Facility Site”). The Facility is a natural gas-fired
cogeneration facility, which has a total electric generating capacity in excess
of 345 megawatts (“MW”) with a maximum average steam output of 400,000
pounds per hour (“lbs/hr”). The Facility consists of one unit
(“Unit 1”) with an electric generating capacity of approximately 79.9
MW and a second unit (“Unit 2”) with an electric generating capacity
of approximately 265 MW. The Public Utilities Regulatory Policies Act of 1978,
as amended (“PURPA”) defines a cogeneration facility as a facility
which produces electric energy and forms of useful thermal energy (such as heat
or steam), used for industrial, commercial, heating or cooling purposes, through
the sequential use of one or more energy inputs. In the case of the Facility,
the Facility uses natural gas as its primary fuel input to produce electric
energy for sale to Niagara Mohawk, Con Edison, 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, 2001, 2000 and 1999, electric sales to Niagara Mohawk
accounted for approximately 16.5%, 18.7% and 19.5%, 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).
4
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 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.
5
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.
- ----------------------------------------------------------------------------
Annual Contract
Contract Volume Quantity
Year MWh MW
- ----------------------------------------------------------------------------
1 325,400 37.146
2 331,000 37.785
3 375,900 42.911
4 417,500 47.660
5 419,500 47.888
6 442,000 50.457
7 451,700 51.564
8 461,300 52.660
9 473,400 54.041
10 485,200 55.388
- ----------------------------------------------------------------------------
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 the power grid, no transmission services are required
for the delivery of power directly to the ISO. The Unit 2 interconnection
facility is necessary to effect the transfer of electricity produced at Unit 2
into Niagara Mohawk’s transmission system. Pursuant to a transmission
services agreement, Niagara Mohawk has agreed to provide firm transmission
services from Unit 2 to the point of interconnection between Niagara
Mohawk’s transmission system and Con Edison’s transmission system for
a period of 20 years from the date of the commencement of commercial operation
of Unit 2.
Con Edison
Unit 2 commenced commercial operation on September 1, 1994 and is selling
265 MW of electric capacity and associated energy to Con Edison under a
long-term contract that allows Con Edison to schedule Unit 2 for dispatch on an
economic basis (the “Con Edison Power Purchase Agreement,” and
together with the Amended and Restated Niagara Mohawk Power Purchase Agreement,
the “Power Purchase Agreements”). The Con Edison Power Purchase
Agreement has a term of 20 years from the date of commencement of commercial
operation of Unit 2, subject to a 10-year extension under certain conditions.
The Con Edison Power Purchase Agreement provides for four payment components:
(i) a capacity payment, (ii) a fuel payment, (iii) an Operations and Maintenance
(“O&M”) payment and (iv) a wheeling payment. The capacity payment,
a portion of the fuel payment, a portion of the O&M payment, and the
wheeling payment are fixed charges to be paid on the basis of plant availability
to operate whether or not Unit 2 is dispatched on-line. The variable portions of
the fuel payment and O&M payment are payable based on the amount of
electricity produced by Unit 2 and delivered to Con Edison. The total fixed and
variable fuel payment is capped at a ceiling price established (and is subject
to adjustment) in accordance with the Con Edison Power Purchase Agreement, and
includes a component, which is equal to one-half of the amount by which Unit
2‘s actual fixed and variable fuel commodity and transportation costs
differs from the ceiling price. For the year ended December 31, 2001, 2000 and
1999 electric sales to Con Edison accounted for approximately 65.2%, 61.5% and
68.1%, respectively, of total project revenues.
6
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 New York Public Service Commission (the
“NYPSC”) approved a plan submitted by Con Edison for the divestiture
of certain of its generating assets (the “Con Edison Divestiture
Plan”). Although the Con Edison Divestiture Plan does not include any
proposal by Con Edison for the sale or other disposition of its contractual
obligations for purchasing power from non-utility generators, like the
Partnership, the NYPSC has ordered Con Edison to submit a report regarding the
feasibility of divesting its non-utility generator entitlements. At this time,
the Partnership has insufficient information to determine whether, in the course
of these proceedings at the NYPSC, Con Edison may seek to assign its rights and
obligations under the Con Edison Power Purchase Agreement with the Partnership
to a third party or to take some other action for the purpose of divesting
itself of the power purchase obligations under such contract; nor can the
Partnership evaluate the impact which any such assignment or other action, if
proposed, may ultimately have on the Con Edison Power Purchase Agreement.
7
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, 2002 and the Partnership intends to renew the
Enabling Agreement through May 2003. 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, 2001, 2000 and 1999, sales to PG&E
Energy Trading accounted for approximately 1.7%%, 6.4% and 3.3%, 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 years
ended December 31, 2001, 2000 and 1999, sales to the ISO accounted for
approximately 8.1%, 0.1% and 0.0% 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.
8
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, 2001, 2000 and
1999, sales to General Electric accounted for approximately 0.0%, 1.1% and 0.5%,
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 Amended and
Restated Niagara Mohawk Power Purchase Agreement. Under the Amended Paramount
Contract, the 15-year term remains unchanged, and the maximum daily quantity of
natural gas that 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”), 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.
9
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, 2001, 2000 and 1999, fuel
revenues accounted for approximately 8.3%, 12.2% and 8.6%, respectively, of
total project revenues.
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.
10
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 that has the objective of
facilitating fair and open competition in the wholesale power market and
creating 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 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 the Partnership’s 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.
11
Seasonality
The Partnership’s reliance on its power purchasers’ customer and
market demand results in the Facility’s dispatch being somewhat affected by
seasonality. Electric markets typically peak during the warmer summer months due
to customer reliance on air conditioning and again during the darker winter
months as customers utilize more lighting. In addition, the gas resale market is
also somewhat seasonal in nature, with the cold winter months tending to drive
up the price of natural gas.
Regulations and Environmental Matters
The Partnership must sell an aggregate annual average of approximately
80,000 lbs/hr from Unit 1 and Unit 2 combined for use as process steam by
General Electric and must satisfy other operating and ownership criteria in
order to comply with the requirements for a Qualifying Facility under PURPA. If
the Facility were to fail to meet such criteria, the Partnership may become
subject to regulation as a subsidiary of a holding company, a public utility
company or an electric utility company under PUHCA, the Federal Power Act (the
“FPA”) and state utility laws. If the Facility loses its Qualifying
Facility status, its Power Purchase Agreements will be subject to the
jurisdiction of the FERC under the FPA. The Partnership may nevertheless be
exempt from regulation under PUHCA if it maintains “exempt wholesale
generator” status. In 1994, the Partnership filed with the FERC an
Application for Determination of Exempt Wholesale Generator Status, which was
granted by the FERC.
In addition to being a Qualifying Facility, Unit 1, prior to the
commencement of operations by Unit 2, was a New York State co-generation
facility under the New York Public Service Law and consequently exempt from most
regulation otherwise applicable under that law to Unit 1‘s steam and
electric operations. The Partnership has obtained from the NYPSC a declaratory
order that the Facility will not be subject to regulation as an electric
corporation, steam corporation or gas corporation under the New York Public
Service Law, except to the extent necessary to implement safety and
environmental regulation. Under certain circumstances, and subject to the
conditions set forth in the Indenture, the Partnership may become subject to
regulation under the New York Public Service Law as an electric corporation,
steam corporation or gas corporation. For example, if the Partnership were to
engage in sales of electricity to General Electric at the GE Plant, the
Partnership could be deemed an electric corporation.
All regulatory approvals currently required to operate the combined
Facility have been obtained. 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 Partnership is subject to federal, state, and local laws and
regulations pertaining to air and water quality, and other environmental
matters. 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.
12
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
Title V operating permit, an application for which was submitted to the DEC
prior to June 9, 1997.
On November 6, 2001, the Partnership received from the DEC the
Facility’s Title V operating permit endorsed by the DEC on November 2, 2001
(the “Title V Permit”). The Title V Permit as received by the
Partnership contains conditions that conflict with the Partnership’s
existing air permits, and the Facility’s compliance with these conditions
under certain operating circumstances would be problematic. Further, the
Partnership believes that certain of the conditions contained in the Title V
Permit are inconsistent with the laws and regulations underlying the Title V
program and Title V operating permits issued by the DEC to comparable electric
generating facilities in New York. By letter dated November 12, 2001, the
Partnership has filed with the DEC a request for an adjudicatory hearing to
address and resolve the issues presented by the Title V Permit, and the terms
and conditions of the Title V Permit will be stayed pending a final DEC decision
on the appeal. At this time it is too early for the Partnership to assess the
likely outcome of the adjudicatory hearing and the impact on the Facility.
In December 1995, the Partnership received a letter from the EPA requesting
revision of the format used by the Partnership for periodic air emission
reporting to the Agency. The Partnership tendered an interim response to the
inquiry in January 1996. As of the date of this report, the Partnership has not
received any further correspondence from the EPA regarding this matter. Although
mutual consensus regarding a reporting format is anticipated, the Partnership
cannot determine what, if any, actions could potentially be taken by the EPA.
13
Employees
The Partnership has no employees. The Project Management Firm provides
overall management and administration services to the Partnership pursuant to a
Project Administrative Services Agreement. The Project Management Firm provides
ten site employees and support personnel in its Boston, Massachusetts and
Bethesda, Maryland offices, who manage Unit 1 and Unit 2 on a combined basis.
General Electric through its O&M services component (the
“Operator”) provides operation and maintenance services for the
Facility pursuant to 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, which is leased by the Partnership
from General Electric. In addition, the Partnership laterally owns an
approximately 2.1 mile pipeline that 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.
14
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.
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. The ISO filed tariff revisions concerning, among other
matters, the suspension of regulation charges on certain generators, including
the Partnership, and subsequently made a filing with the FERC that provided the
rationale for exempting certain generators, including the Partnership, from
potential reimposition of regulation charges. On October 3, 2001, the FERC
accepted the ISO filing.
15
Curtailment
In October 1992, the NYPSC initiated a proceeding to investigate whether
conditions existed which justified the exercise by power purchasing petitioners,
including Niagara Mohawk and Con Edison, of certain powers granted under PURPA
and the regulations promulgated thereunder to curtail purchases from, and avoid
payment obligations to, non-utility generators, including Qualifying Facilities
such as the Facility during certain periods. 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.
Con Edison has not expressly waived 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.
16
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,
-------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
Statement of Operations
Data:
Operating revenues $229,725 $234,377 $177,468 $172,739 $184,111
Cost of revenues 154,546 163,389 117,331 119,240 133,833
Other operating expenses 5,496 5,541 4,553 5,130 6,584
Operating income 69,683 65,447 55,584 48,369 43,694
Net interest expense 30,799 30,899 31,687 32,048 32,234
---------- ---------- --------- --------- ----------
Income before cumulative
effect of a change in
accounting principle 38,884 34,548 23,897 16,321 11,460
Cumulative effect of a change
in accounting principle (519) 7,866 --- --- ---
-------- -------- ---------- --------- ----------
Net income $ 38,365 $ 42,414 $ 23,897 $ 16,321 $ 11,460
======== ========= ========== ========= ==========
17
December 31,
-----------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
Balance Sheet Data:
Plant and equipment, net $273,913 $285,324 $297,034 $308,999 $321,537
Total assets 347,963 358,942 367,087 373,877 385,874
Long-term bonds,
net of current portion 349,235 362,764 373,826 381,133 385,955
Partners' deficits (55,783) (49,646) (50,832) (46,810) (32,282)
Supplementary Financial Information
The following is a summary of the quarterly results of operations for the
years ended December 31, 1999, December 31, 2000 and December 31, 2001.
Three Months Ended (unaudited)
------------------------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands)
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
Year Ended
December 31, 2001
Operating revenues $ 66,473 $ 57,677 $ 53,124 $ 52,451
Gross Profit 19,565 14,987 19,791 20,836
Income before cumulative
effect of a change in
accounting principle 10,616 5,860 10,604 11,804
Cumulative effect of a change
in accounting principle --- --- (519) ---
Net income 10,616 5,860 10,085 11,804
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 (see Note 8 to the Consolidated
Financial Statements).
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 $38.4 million,
$42.4 million and $23.9 million in 2001, 2000 and 1999, respectively, and made
cash distributions to the partners of approximately $35.7 million, $41.2 million
and $27.9 million in 2001, 2000 and 1999, respectively.
Results of Operations
Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000
The Partnership earned net income of approximately $38.4 million for the
year ended December 31, 2001 as compared to net income of approximately $42.4
million for the prior year. The $4.0 million decrease in net income is primarily
due to the Partnership recording income in the prior year of approximately $7.9
million reflecting the cumulative effect of a change in accounting principle,
partially offset by higher Unit 2 electric revenues during the year ended
December 31, 2001.
Effective July 1, 2001, the Partnership determined that certain gas
contracts no longer meet the definition of normal purchases and sales and are no
longer exempt from the requirements of Statement of Financial Accounting
Standards (“SFAS”) No. 133. The cumulative effect of a change in
accounting principle was a loss of approximately $0.5 million. Changes in the
fair value of the contracts are recorded on the consolidated statements of
operations as an unrealized gain or loss. See Note 2 to the Consolidated
Financial Statements for a discussion of the Partnership’s accounting for
derivative contracts.
19
Effective January 1, 2000, the Partnership changed its method of accounting
for major maintenance and overhaul costs. Beginning January 1, 2000, the cost of
major maintenance and overhauls is expensed as incurred. Previously, the
estimated cost of major maintenance and overhauls was accrued in advance in a
systematic and rational manner over the period between major maintenance and
overhauls.
Total revenues for the year ended December 31, 2001 were approximately
$229.7 million as compared to approximately $234.4 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 2001 December 31, 2000
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 59.2 510.5 73.24% 77.58% 58.9 617.1 88.60% 95.67%
Unit 2 151.3 2,046.0 87.82% 92.15% 144.0 1,835.8 78.87% 87.85%
The “capacity factor” of Unit 1 and Unit 2 is the amount of
energy produced by each Unit in a given time period expressed as a percentage of
the total contract capability amount of potential energy production in that time
period.
The “dispatch factor” of Unit 1 and Unit 2 is the number of hours
scheduled for electric delivery (regardless of output level) in a given time
period expressed as a percentage of the total number of hours in that time
period.
Revenues from Unit 1 increased approximately $0.3 million for the year
ended December 31, 2001 as compared to the prior year. During the year ended
December 31, 2001, revenues from Niagara Mohawk, PG&E Energy Trading and the
ISO were approximately $37.8 million, $3.9 million and $17.5 million as compared
to approximately $43.8 million, $14.9 million and $0.2 million, respectively,
for the prior year. The increase in Unit 1 revenues for the year ended December
31, 2001 was primarily due to an increase in Monthly Contract Payments,
partially offset by decreases in market energy prices and volume of delivered
energy. The decrease in volume of delivered energy was primarily due to a seven
week scheduled maintenance outage in the spring of 2001. During the years ended
December 31, 2001 and 2000, with the exception of the month of April 2001 and
2000, the Partnership received Monthly Contract Payments from Niagara Mohawk.
Effective with the termination of Transitional Rights on October 31, 2000,
Niagara Mohawk ceased to be obligated to purchase energy up to the monthly
contract quantity (“Contract Energy”) or capacity associated with
Contract Energy (“Contract Capacity”) from the Partnership.
20
During the year ended December 31, 2001, the Partnership did not deliver
any Contract Energy to Niagara Mohawk. During the year ended December 31, 2001,
with the exception of the months of January 2001, March 2001 and April 2001, the
Partnership sold all of the energy produced by Unit 1 to the ISO. During the
month of January 2001, the Partnership sold all of the energy produced by Unit 1
to PG&E Energy Trading. During the months of March 2001 and April 2001, the
Partnership did not sell any energy from Unit 1. During the year ended December
31, 2000, with the exception of the months of April 2000, November 2000,
December 2000, the Partnership delivered Contract Energy to Niagara Mohawk.
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 year ended December 31, 2001, the Partnership did not sell any
Contract Capacity to Niagara Mohawk. During the months of January 2001 through
April 2001 and November 2001 and December 2001, the Partnership sold all of the
capacity associated with Unit 1 to the ISO. During the months of May 2001
through October 2001, the Partnership sold all of the capacity associated with
Unit 1 to both PG&E Energy Trading and the ISO. During the year ended
December 31, 2000, with the exception of November 2000 and December 2000, the
Partnership sold Contract Capacity to Niagara Mohawk and capacity in excess of
Contract Capacity (“Unit 1 Excess Capacity”) to PG&E Energy
Trading. During the months of November 2000 and December 2000, the Partnership
sold all of the capacity associated with Unit 1 to the ISO.
Contract Energy sales to Niagara Mohawk, Contract Capacity sales to Niagara
Mohawk, energy sales to the ISO and capacity sales to the ISO were sold at ISO
market clearing prices. Unit 1 Excess Energy sales to PG&E Energy Trading
and Niagara Mohawk, Unit 1 Excess Capacity sales to PG&E Energy Trading, and
energy and capacity sales to PG&E Energy Trading were sold at negotiated
market prices. Amortized deferred revenues of approximately $0.7 million are
also included in revenues from Niagara Mohawk for the years ended December 31,
2001 and 2000.
Revenues from Unit 2 increased approximately $7.3 million for the year
ended December 31, 2001 as compared to the prior year. During the year ended
December 31, 2001, Unit 2 revenues from Con Edison, the ISO and unrelated third
parties were approximately $149.7 million, $1.2 million and $0.4 million as
compared to approximately $144.0 million, $0.0 million and $0.0 million,
respectively, for the prior year. The increase in revenues from Unit 2 for the
year ended December 31, 2001 was primarily due to increases in the Con Edison
capacity payment and volume of delivered energy. During the year ended December
31, 2001, revenues from the ISO and unrelated third parties resulted from the
sales of other energy related products.
Steam revenues for the years ended December 31, 2001 and 2000 of
approximately $0.8 million and $2.6 million, respectively, were reduced by a
reserve of approximately the same amount and $51.3 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 (the “Discounted
Quantity”). Delivered steam for the year ended December 31, 2001 was
approximately 1.4 billion pounds or 159,998 lbs/hr as compared to approximately
1.8 billion pounds or 204,568 lbs/hr in the prior year. The decrease in steam
revenues for the year ended December 31, 2001 was primarily due to the decrease
in steam sales in excess of the Discounted Quantity to General Electric.
21
Fuel revenues for the year ended December 31, 2001 were approximately $19.2
million as compared to $28.8 million for the prior year. Gas resale revenues for
the year ended December 31, 2001 were approximately $15.6 million on sales of
approximately 2.9 million MMBtu’s as compared to approximately $15.2
million on sales of approximately 3.6 million MMBtu’s for the prior year.
The $0.4 million increase in gas resale revenues during the year ended December
31, 2001 is primarily due to higher natural gas resale prices, partially offset
by higher dispatch of Unit 2, which resulted in lower volumes of natural gas
becoming available for resale. The increase in natural gas resale prices during
the year ended December 31, 2001 generally resulted from higher market pricing
for both gas and oil. 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, 2001 were approximately $2.9 million on sales of approximately 0.8
million MMBtu’s as compared to approximately $11.5 million on sales of
approximately 3.6 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, 2001 were approximately $.7 million on sales of approximately 0.0
thousand MMBtu’s as compared to approximately $2.1 million on sales of
approximately 182 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, 2001 were
approximately $125.1 million as compared to approximately $134.3 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,
2001 were approximately $113.5 million on purchases of approximately 27.9
million MMBtu’s as compared to approximately $115.2 million on purchases of
approximately 28.3 million MMBtu’s for the prior year. The $1.7 million
decrease in the cost of fuel was primarily due to the Partnership recording
additional gas import tax in the prior year of approximately $1.0 million
resulting from the settlement of a gas import tax audit, partially offset by a
decrease in the volume of gas purchased under the Unit 1 firm fuel supply
contract resulting from the seven week scheduled maintenance outage in the
spring of 2001. Fuel costs associated with gas optimizations for the year ended
December 31, 2001 were approximately $2.9 million on purchases of approximately
0.8 million MMBtu’s as compared to approximately $10.7 million on purchases
of approximately 3.6 million MMBtu’s. There were no fuel costs associated
with peak shaving arrangements for the year ended December 31, 2001, as compared
to $0.8 million on purchases of 182 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, 2001 and
2000, fuel costs were increased by approximately $3.2 million and $2.5 million,
respectively, as a result of the currency swap agreements. Transmission costs
for the years ended December 31, 2001 and 2000 were approximately $8.7 million
and $7.6 million, respectively.
22
Unrealized gain on derivative contracts for the year ended December 31,
2001 was approximately $1.0 million. The unrealized gain reflects the change in
the fair value of peak shaving arrangements as of December 31, 2001. See Note 2
to the Consolidated Financial Statements for a discussion of the
Partnership’s accounting for derivative contracts.
Other operating and maintenance expenses for the year ended December 31,
2001 were approximately $18.0 million as compared to approximately $16.6 million
for the prior year. The $1.4 million increase in other operating and maintenance
expenses was primarily due to differences in the scheduling of planned
maintenance.
Total other operating expenses, excluding amortization of deferred
financing charges, of approximately $4.4 million for the year ended December 31,
2001 were comparable to the prior year.
Amortization of deferred financing charges of approximately $1.1 million
for the year ended December 31, 2001 was comparable to the prior year. Deferred
financing charges are amortized using the effective interest method.
Net interest expense of approximately $30.8 million for the year ended
December 31, 2001 was comparable to the prior year.
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 1999,
then the pro forma effect (unaudited) for 1999 would have increased net income
by approximately $1.3 million.
23
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%
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
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. 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 Contract Energy to Niagara Mohawk. Effective
with the termination of Transitional Rights on October 31, 2000, Niagara Mohawk
ceased to be obligated to purchase Contract Energy. Commencing on November 18,
1999, Contract Energy was sold at market prices established by the ISO. 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 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.
24
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.
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 or 204,568
lbs/hr as compared to approximately 1.6 billion pounds or 181,027 lbs/hr 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.
25
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
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.
26
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.
Liquidity and Capital Resources
Net cash provided by operating activities for the year ended December 31,
2001 was approximately $49.6 million as compared to approximately $52.1 million
for the prior year. Net cash provided by operating activities primarily
represents net income, adjusted by non-cash expenses and income, plus the net
effect of changes within the Partnership’s operating assets and liability
accounts.
Net cash used in investing activities for the year ended December 31, 2001
was approximately $1.2 million as compared to approximately $0.8 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, 2001
was approximately $47.1 million as compared to approximately $49.8 million for
the prior year. The decrease in net cash used in financing activities for the
year ended December 31, 2001 was primarily due to less cash becoming available
to distribute to the Partners, partially offset by the increase in semi-annual
payments 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, 2001 and 2000 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 2001 calculated pursuant to the
Indenture was 1.84:1.
27
Credit Agreement
The Partnership has available for its use a credit agreement, as amended
(“Credit Agreement”), with a maximum available credit of approximately
$7.5 million though 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 purposes
of meeting letters of credit requirements under various project contracts and
for meeting working capital requirements. The maximum amount available under the
Credit Agreement for working capital purposes is $5.0 million. As of December
31, 2001 and 2000, there were no amounts drawn or balances outstanding under
either the letters of credit or the working capital arrangement.
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 trustee (the
“Trustee”). 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 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 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, 2001 and 2000, the balance in this Fund was
approximately $4.1 million and $3.9 million, respectively. During the year
ending December 31, 2002, deposits of approximately $10.9 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 Requirements for the
Interest and Principal Funds are the amounts due and payable on the next
semi-annual payment date. On December 26, 2001 and 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, 2001 and 2000. The June 26, 2002 Interest
and Principal Fund Requirements will be approximately $16.1 million and
approximately $6.6 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 the Bonds outstanding
for any six-month period during the succeeding three-year period. At December
31, 2001 and 2000, the balance in the Debt Service Reserve Fund was
approximately $24.3 million and $24.0 million, respectively. The June 26, 2002
Fund Requirement will remain at approximately $24.3 million.
The Partnership Distribution Fund has the lowest priority in the Fund
hierarchy and cash distributions to the Partners from this Fund 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.
Year Ending December 31, 2002
During 2002, the Partnership anticipates Con Edison to dispatch 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 2002, natural gas resale prices and the price
of natural gas under the firm fuel contracts have been below prior year prices
and the Partnership anticipates, on the average, such prices to remain below
2001 levels for the balance of 2002.
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 during 2002.
29
Commitments
The Partnership has entered into various long-term firm commitments with
approximate dollar obligations as follows (in thousands).
2007 and
---------
2002 2003 2004 2005 2006 Thereafter
---- ---- ---- ---- ---- ----------
Fuel Supply and Transportation
Agreements $53,402 $55,121 $56,802 $56,224 $57,506 $413,236
Electric Interconnection and
Transmission Agreements 600 600 600 600 600 4,250
Site Lease 1,000 1,000 1,000 1,000 1,000 7,667
Payment in Lieu of Taxes 3,100 3,300 3,500 3,700 3,800 24,900
Fuel Supply and Transportation Agreements – The Partnership has
a firm natural gas supply agreement with Paramount for Unit 1. The
agreement has an initial term of 15 years that began November 1, 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, 2001, 2000, and 1999, the Partnership purchased gas totaling
approximately $53.8 million, $55.9 million and $34.2 million, respectively,
under these agreements.
The Partnership has three firm fuel transportation service agreements for
Unit 1, each with a 20-year term commencing November 1, 1992.
The Partnership has three firm fuel transportation service agreements for
Unit 2, each with a 20-year term commencing November 1, 1994. Under one of these
agreements, the Partnership has posted a letter of credit for approximately $2.5
million U.S. dollars and two fuel suppliers, on behalf of the Partnership, have
posted letters of credit totaling approximately $8.3 million Canadian dollars.
The Partnership is obligated to reimburse the fuel suppliers for all costs
related to obtaining and maintaining the letters of credit.
Electric Interconnection and Transmission Agreements–The
Partnership constructed an interconnection facility to interconnect the
power output from Unit 1 to Niagara Mohawk’s electric transmission system
and has transferred title of this interconnection facility to Niagara Mohawk.
The Partnership has agreed to reimburse Niagara Mohawk $150.0 thousand 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.
30
The Partnership has a 20-year firm transmission agreement with Niagara
Mohawk to transmit the power output 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 title to the facility to
Niagara Mohawk. Under the terms of this agreement, the Partnership will
reimburse Niagara Mohawk $450.0 thousand 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 is approximately $1.0
million.
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 certain property taxes. The agreement commenced on
January 1, 1993, and will terminate on December 31, 2012. PILOT payments are due
semi-annually in equal installments.
Other Commitments
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 $1.0 million
of water supply annually. The agreement is subject to adjustment for changes in
market rates beginning in October 2002.
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 2001 interest rates would have
resulted in a negative impact of approximately $0.2 million on the
Partnership’s net income.
31
The Partnership’s 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.
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, 2001, the exchange rate
differential had a negative impact of approximately $3.2 million on the
Partnership’s net income (see Notes 3 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.
New Accounting Pronouncements
The Partnership adopted Statement of Financial Accounting Standards
(“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS Nos. 137 and 138 (collectively, the
“Statement”), on January 1, 2001. The Statement requires the
Partnership to recognize all derivatives, as defined in the Statement, on the
consolidated balance sheets at fair value. The transition adjustment to
implement the Statement was a negative adjustment of approximately $9.0 million
to other comprehensive income, a component of partners’ equity and had no
effect on net income on January 1, 2001. Derivatives are classified as asset for
derivative contracts and liability for derivative contracts on the consolidated
balance sheets. The Partnership has two foreign currency exchange contracts to
hedge fluctuations of fuel transportation costs denominated in Canadian dollars.
The fair value of these contracts is recorded on the consolidated balance sheets
as a liability for derivative contracts (see Note 3 to the Consolidated
Financial Statements).
Derivatives, or any portion thereof, that are not 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 (loss) until the hedged items are recognized in earnings.
Net gains or losses on derivative contracts recognized for the year ended
December 31, 2001 were included in various lines of the cost of revenues section
of the consolidated statements of operations.
32
The Partnership also has certain derivative commodity contracts for the
physical delivery of purchase and sale quantities transacted in the normal
course of business. These derivatives are exempt from the requirements of the
Statement under the normal purchases and sales exception, and thus are not
reflected on the consolidated balance sheet at fair value. In June, 2001 (as
amended in October 2001 and December 2001), the Financial Accounting Standards
Board (“FASB”) approved an interpretation issued by the Derivatives
Implementation Group (“DIG”), Issue No. C-15 that changed the
definition of normal purchases and sales for certain power contracts. The
Partnership must implement this interpretation on April 1, 2002, and is
currently assessing the impact of these new rules.
33
In June 2001, the FASB issued SFAS No. 143, entitled, Accounting for Asset
Retirement Obligations. This standard is effective for fiscal years beginning
after June 15, 2002, and provides accounting requirements for asset retirement
obligations associated with tangible long-lived assets. Under the standard, the
asset retirement obligation is recorded at fair value in the period in which it
is incurred by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its present value in each subsequent period and the
capitalized cost is depreciated over the useful life of the related assets. The
Partnership has not yet determined the effects of this standard on its financial
reporting.
34
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
35
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING
The FASB has also approved DIG Issue Nos. C-10 and C-16 that disallow
normal purchases and sales treatment for commodity contracts (other than power
contracts) that contain volumetric variability or optionality. Certain of the
Partnership’s derivative commodity contracts may no longer be exempt from
the requirements of the Statement. Effective July 1, 2001, the Partnership
recorded on the consolidated balance sheets a liability for derivative contracts
for certain of its gas contracts. The Partnership has determined such contracts
no longer meet the definition of normal purchases and sales and are no longer
exempt from the requirements of the Statement as a result of the DIG’s
interpretative guidance under Issue No. C-10. The cumulative effect of a change
in accounting principle was a loss of approximately $0.5 million. Changes in the
fair value of the contracts are recorded on the consolidated statements of
operations as an unrealized gain or loss. With respect to Issue No. C-16, the
Partnership is evaluating the impact of this implementation guidance on its
consolidated financial statements, and will implement this guidance, as
appropriate, by the implementation deadline of April 1, 2002.
The fair values of derivative contracts are based on management’s best
estimates considering various factors including market quotes, forward price
curves, time value, and volatility factors. The values are adjusted to reflect
the potential impact of liquidating a position in an orderly manner over a
reasonable period of time under present market conditions and to reflect
creditworthiness of the counterparty.
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.
Critical Accounting Policies
Effective January 1, 2001, the Partnership adopted SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137
and 138 (collectively, the “Statement”). The Statement requires the
Partnership to recognize all derivatives, as defined in the Statement, on the
consolidated balance sheets at fair value (see Note 2 to the Consolidated
Financial Statements - Accounting for Derivative Contracts).
Legal Matters
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. See Part I, Item 3 of this Report for further discussion of
significant pending litigation.
Regulations and Environmental Matters
On November 6, 2001, the Partnership received from the DEC the
Facility’s Title V operating permit endorsed by the DEC on November 2, 2001
(the “Title V Permit”). The Title V Permit as received by the
Partnership contains conditions that conflict with the Partnership’s
existing air permits, and the Facility’s compliance with these conditions
under certain operating circumstances would be problematic. Further, the
Partnership believes that certain of the conditions contained in the Title V
Permit are inconsistent with the laws and regulations underlying the Title V
program and Title V operating permits issued by the DEC to comparable electric
generating facilities in New York. By letter dated November 12, 2001, the
Partnership has filed with the DEC a request for an adjudicatory hearing to
address and resolve the issues presented by the Title V Permit, and the terms
and conditions of the Title V Permit will be stayed pending a final DEC decision
on the appeal. At this time it is too early for the Partnership to assess the
likely outcome of the adjudicatory hearing and the impact on the
Facility.
Information responding to Item 7A appears in the “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations”.
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.
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................ 51 President and Director
Sanford L. Hartman............... 48 Director
John R. Cooper................... 54 Senior Vice President and Chief
Financial Officer
Ernest K. Hauser................. 52 Senior Vice President
David N. Bassett................. 55 Treasurer
Managing General Partner:
Name Age Position
---- --- --------
P. Chrisman Iribe.................. 51 President and Director
Sanford L. Hartman................. 48 Director
John R. Cooper..................... 54 Senior Vice President and Chief
Financial Officer
Ernest K. Hauser................... 52 Senior Vice President
David N. Bassett................... 55 Treasurer
36
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 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 President of both
the Funding Corporation and the Managing General Partner since 1998. 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, an affiliate of the Partnership, 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. Mr. Hartman has been a Director of both the Funding Corporation
and the Managing General Partner since 1999.
John R. Cooper is Senior Vice President and Chief Financial Officer
of PG&E National Energy Group Company, an affiliate of the Partnership, 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. Mr. Cooper has
been Senior Vice President and Chief Financial Officer of both the Funding
Corporation and the Managing General Partner since 1996.
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.
Mr. Hauser has been Senior Vice President of both the Funding Corporation and
the Managing General Partner since 2000.
David N. Bassett is Vice President, Controller and Treasurer of
PG&E National Energy Group Company, an affiliate of the Partnership, 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. Mr. Bassett has been Treasurer of both the Funding
Corporation and the Managing General Partner since 1996.
37
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.
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, 2001 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%
20 Waterview Blvd. (ii) 20.0000%
Parsippany, New Jersey 07054 (iii) 17.7000%
38
* 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. Each of the persons listed has sole voting power
and sole investment power with respect to the beneficial
ownership interests described, subject to certain partnership
interest pledge agreements made in favor of the Funding
Corporation’s and the Partnership’s lenders.
(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.
39
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
JMCS I Management, an indirect, wholly-owned subsidiary of PG&E
Corporation, 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 9 to the Consolidated Financial Statements for a discussion
of the Partnership’s related party transactions.
40
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, 2001,
2000, and 1999........................................................... F-1
Consolidated Balance Sheets as of December 31, 2001 and 2000.............. F-2
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999......................................... F-3
Consolidated Statements of Changes in Partners' Deficits for the
years ended December 31, 2001, 2000 and 1999............................. F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999......................................... F-5
Notes to Consolidated Financial Statements................................ F-6
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.
41
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, 2001 and 2000,
and the related consolidated statements of operations, changes in partners’
deficits, and cash flows for each of the three years in the period ended
December 31, 2001. 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, 2001 and
2000, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
See Note 1 of the financial statements for discussion of the bankruptcy of an
affiliated company.
As discussed in Note 2 of the Notes to the Financial Statements, the Partnership
adopted Statement of Financial Accounting Standards No. 133, “Accounting
for Derivative Instruments and Hedging Activities”, as amended by Statement
of Financial Accounting Standards No. 138, “Accounting for Certain
Derivatives and Hedging Activities”, effective January 1, 2001.
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
February 15, 2002
F-1
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(In Thousands)
- -------------------------------------------------------------------------------------------------------------------------
2001 2000
------------------ ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 4,546 $ 3,187
Restricted funds 7,699 5,089
Accounts receivable, net of allowance of $32 and $174
in 2001 and 2000, respectively 17,789 20,097
Due from affiliates 1,127 3,882
Fuel inventory and supplies 10,228 6,693
Other current assets 511 436
Asset for derivative contracts 446 ---
------------------ ----------------
Total current assets 42,346 39,384
------------------ ----------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 373,476 372,443
Less: Accumulated depreciation 99,563 87,119
------------------ ----------------
Plant and equipment, net 273,913 285,324
------------------ ----------------
LONG-TERM RESTRICTED FUNDS 24,314 25,732
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $8,901 and $7,789, respectively in 2001
and 2000, respectively 7,390 8,502
------------------ ----------------
TOTAL ASSETS $ 347,963 $ 358,942
================== ================
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 1,729 $ 49
Accrued fuel expenses 8,689 15,168
Accrued property taxes 2,296 3,250
Other accrued expenses 5,792 3,106
Due to affiliates 2,008 635
Current portion of long-term bonds 13,529 11,062
Current portion of liability for derivative contracts 3,688 ---
------------------ ----------------
Total current liabilities 37,731 33,270
LONG-TERM LIABILITIES:
Deferred revenue 4,597 5,304
Other long-term liabilities 7,070 7,250
Long-term bonds - net of current portion 349,235 362,764
Liability for derivative contracts - net of current portion 5,113 ---
------------------ ----------------
Total liabilities 403,746 408,588
------------------ ----------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (458) (485)
Limited partners' deficits (46,524) (49,161)
Accumulated other comprehensive loss (8,801) ---
------------------ ----------------
Total partners' deficits (55,783) (49,646)
------------------ ----------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 347,963 $ 358,942
================== ================
See notes to consolidated financial statements.
F-2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
2001 2000 1999
--------------- --------------- ----------------
OPERATING REVENUES:
Electric and steam $ 210,504 $ 205,539 $ 162,111
Fuel revenues 19,221 28,838 15,357
--------------- --------------- ----------------
Total operating revenues 229,725 234,377 177,468
--------------- --------------- ----------------
COST OF REVENUES:
Fuel and transmission costs 125,055 134,272 87,226
Unrealized gain on derivative contracts (965) --- ---
Other operating and maintenance 17,973 16,649 17,652
Depreciation 12,483 12,468 12,453
--------------- --------------- ----------------
Total cost of revenues 154,546 163,389 117,331
--------------- --------------- ----------------
GROSS PROFIT 75,179 70,988 60,137
--------------- --------------- ----------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 1,898 2,244 1,802
Other general and administrative 2,486 2,169 1,599
Amortization of deferred financing charges 1,112 1,128 1,152
--------------- --------------- ----------------
Total other operating expenses 5,496 5,541 4,553
--------------- --------------- ----------------
OPERATING INCOME 69,683 65,447 55,584
--------------- --------------- ----------------
INTEREST (INCOME) EXPENSE:
Interest income (2,015) (3,176) (2,355)
Interest expense 32,814 34,075 34,042
--------------- --------------- ----------------
Total interest expense, net 30,799 30,899 31,687
--------------- --------------- ----------------
Income before cumulative effect of a change
in accounting principle 38,884 34,548 23,897
Cumulative effect of a change in
accounting principle (519) 7,866 ---
--------------- --------------- ----------------
NET INCOME $ 38,365 $ 42,414 $ 23,897
=============== =============== ================
NET INCOME ALLOCATION:
General partners $ 385 $ 425 $ 239
Limited partners 37,980 41,989 23,658
--------------- ---------------- ----------------
TOTAL $ 38,365 $ 42,414 $ 23,897
=============== =============== ================
See notes to consolidated financial statements.
F-3
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ DEFICITS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Accumulated
Other
General Limited Comprehensive Total Partners'
Partners Partners Income (Loss) Deficits
---------------- ---------------- ----------------- ------------------
BALANCE, JANUARY 1, 1999 $ (457) $ (46,353) $ --- $ (46,810)
Net income 239 23,658 --- 23,897
---------------- ---------------- ----------------- ------------------
Comprehensive Income 239 23,658 --- 23,897
---------------- ---------------- ----------------- ------------------
Capital distributions (279) (27,640) --- (27,919)
---------------- ---------------- ----------------- ------------------
BALANCE, DECEMBER 31, 1999 (497) (50,335) --- (50,832)
Net income 425 41,989 --- 42,414
---------------- ---------------- ----------------- ------------------
Comprehensive Income 425 41,989 --- 42,414
---------------- ---------------- ----------------- ------------------
Capital distributions (413) (40,815) --- (41,228)
---------------- ---------------- ----------------- ------------------
BALANCE, DECEMBER 31, 2000 (485) (49,161) --- (49,646)
Net income 385 37,980 --- 38,365
Other comprehensive loss --- --- (8,801) (8,801)
---------------- ---------------- ----------------- ------------------
Comprehensive Income 385 37,980 (8,801) 29,564
---------------- ---------------- ----------------- ------------------
Capital distributions (358) (35,343) --- (35,701)
---------------- ---------------- ----------------- ------------------
BALANCE, DECEMBER 31, 2001 $ (458) $ (46,524) $ (8,801) $ (55,783)
================ ================ ================= ==================
See notes to consolidated financial statements.
F-4
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Thousands)
2001 2000 1999
-------------- -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,365 $ 42,414 $ 23,897
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of a change in accounting principle 519 (7,866) ---
Depreciation and amortization 13,595 13,596 13,605
Loss on disposal of equipment 92 17 ---
Unrealized gain on derivative contracts (965) --- ---
Deferred revenue (707) (677) (584)
Increase (decrease) in cash resulting from a change in:
Restricted funds (856) 6,205 (3,229)
Accounts receivable 2,308 (4,592) (1,730)
Due from affiliates 2,755 (3,455) 316
Fuel inventory and supplies (3,535) 138 (1,798)
Other current assets (75) (241) 138
Accounts payable 1,680 (2,077) 1,509
Accrued fuel expenses (6,479) 7,070 (31)
Accrued property taxes (954) 550 200
Other accrued expenses 2,686 790 (413)
Due to affiliates 1,373 166 (170)
Other long-term liabilities (180) 20 1,543
-------------- -------------- --------------
Net cash provided by operating activities 49,622 52,058 33,253
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (1,174) (775) (488)
Proceeds from disposal of equipment 10 --- ---
-------------- -------------- --------------
Net cash used in investing activities (1,164) (775) (488)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds (336) (1,293) (131)
Distributions to partners (35,701) (41,228) (27,919)
Repayment of long-term debt (11,062) (7,307) (4,822)
-------------- -------------- --------------
Net cash used in financing activities (47,099) (49,828) (32,872)
-------------- -------------- --------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,359 1,455 (107)
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 3,187 1,732 1,839
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
END OF YEAR $ 4,546 $ 3,187 $ 1,732
============== ============== ==============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 32,825 $ 34,082 $ 34,047
============== ============== ==============
See notes to consolidated financial statements.
F-5
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
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 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 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 8). 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 an indirect, 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.
F-6
In December 2000, and in January and February 2001, PG&E Corporation and NEG
completed a corporate restructuring of NEG, known as a “ringfencing”
transaction. The ringfencing involved the use or creation of limited liability
companies (“LLCs”) as intermediate owners between a parent company and
its subsidiaries. One of these LLCs is PG&E National Energy Group, LLC,
which owns 100% of the stock of NEG. After the ringfencing structure was
implemented, two independent rating agencies, Standard and Poor’s and
Moody’s Investor Services issued investment grade ratings for NEG and
reaffirmed such ratings for certain NEG subsidiaries. On April 6, 2001, Pacific
Gas and Electric Company (the “Utility”), another subsidiary of
PG&E Corporation, filed a voluntary petition for relief under the provisions
of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S.
Bankruptcy Code, the Utility retains control of its assets and is authorized to
operate its business as a debtor-in-possession while being subject to the
jurisdiction of the Bankruptcy Court. On September 20, 2001, the Utility and
PG&E Corporation jointly filed a plan of reorganization that entails
separating the Utility into four distinct businesses. The plan of reorganization
does not directly affect NEG or any of its subsidiaries. Subsequent to the
bankruptcy filing, the investment grade ratings of NEG and its rated
subsidiaries were reaffirmed on April 6 and 9, 2001. The Managing General
Partner believes that NEG and its direct and indirect subsidiaries as described
above, including JMC Selkirk, Inc., PentaGen Investors, L.P., or the
Partnership, would not be substantively consolidated with PG&E Corporation
in any insolvency or bankruptcy proceeding involving PG&E Corporation or the
Utility.
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. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, liabilities and disclosure of contingencies at the
date of the consolidated financial statements. Actual results could differ from
these 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.
Accounting for Derivative Contracts - The Partnership adopted Statement
of Financial Accounting Standards (“SFAS”) No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and
138 (collectively, the “Statement”), on January 1, 2001. The Statement
requires the Partnership to recognize all derivatives, as defined in the
Statement, on the consolidated balance sheets at fair value. The transition
adjustment to implement the Statement was a negative adjustment of approximately
$8,968,000 to other comprehensive income, a component of partners’ equity
and had no affect on net income on January 1, 2001. Derivatives are classified
as asset for derivative contracts and liability for derivative contracts on the
consolidated balance sheets. The Partnership has two foreign currency exchange
contracts to hedge fluctuations of fuel transportation costs denominated in
Canadian dollars. The fair value of these contracts is recorded on the
consolidated balance sheets as a liability for derivative contracts (Note
3).
F-7
Derivatives, or any portion thereof, that are not 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 (loss) until the hedged items are recognized in earnings.
Net gains or losses on derivative contracts recognized for the year ended
December 31, 2001, were included in various lines of the cost of revenues
section of the consolidated statements of operations.
The Partnership also has certain derivative commodity contracts for the physical
delivery of purchase and sale quantities transacted in the normal course of
business. These derivatives are exempt from the requirements of the Statement
under the normal purchase and sales exception, and thus are not reflected on the
consolidated balance sheets at fair value. In June, 2001 (as amended in October
2001 and December 2001), the Financial Accounting Standards Board
(“FASB”) approved an interpretation issued by the Derivatives
Implementation Group (“DIG”), Issue No. C-15 that changed the
definition of normal purchases and sales for certain power contracts. The
Partnership must implement this interpretation on April 1, 2002, and is
currently assessing the impact of these new rules.
The FASB has also approved DIG Issue Nos. C-10 and C-16 that disallow normal
purchases and sales treatment for commodity contracts (other than power
contracts) that contain volumetric variability or optionality. Certain of the
Partnership’s derivative commodity contracts may no longer be exempt from
the requirements of the Statement. Effective July 1, 2001, the Partnership
recorded on the consolidated balance sheets a liability for derivative contracts
for certain of its gas contracts. The Partnership has determined such contracts
no longer meet the definition of normal purchases and sales and are no longer
exempt from the requirements of the Statement as a result of the DIG’s
interpretative guidance under Issue No. C-10. The cumulative effect of a change
in accounting principle was a loss of approximately $519,000. Changes in the
fair value of the contracts are recorded on the consolidated statements of
operations as an unrealized gain or loss. With respect to Issue No. C-16, the
Partnership is evaluating the impact of this implementation guidance on its
consolidated financial statements, and will implement this guidance, as
appropriate, by the implementation deadline of April 1, 2002.
The fair values of derivative contracts are based on management’s best
estimates considering various factors including market quotes, forward price
curves, time value, and volatility factors. The values are adjusted to reflect
the potential impact of liquidating a position in an orderly manner over a
reasonable period of time under present market conditions and to reflect
creditworthiness of the counterparty.
Cash Equivalents - For the purposes
of the accompanying consolidated statements of cash flows, the Partnership
considers all unrestricted, highly liquid investments with original maturities
of three months or less to be cash equivalents.
Restricted Funds and Long-Term Restricted Funds -
Restricted funds and long-term restricted funds include cash
and cash equivalents whose use is restricted under a deposit and disbursement
agreement (the “D&D Agreement”) (Note 5). Restricted funds
associated with transactions or events occurring beyond one year are classified
as long-term. All other restricted funds are classified as current
assets.
Fuel Inventory and Supplies -
Inventories are stated at the lower of cost or market. Costs
for materials, supplies and fuel oil inventories are determined on an average
cost method. As of December 31, 2001 and 2000, fuel inventory and supplies
consisted mainly of spare parts.
In 2001 the Partnership purchased spare parts with a value of approximately
$5,284,000 from an unrelated third party. In consideration for the purchase of
the spare parts, the Partnership exchanged cash and spare parts previously
included in inventory. The cash and fair value of the spare parts exchanged were
equivalent to the fair value of the spare parts received, and as such, no gain
or loss was recorded.
F-8
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 (Note 8) 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 8).
Accumulated Other Comprehensive Income (Loss)–Accumulated other
comprehensive income (loss) reports a measure for changes in equity of an
enterprise that result from transactions and other economic events other than
transactions with partners. The Partnership’s accumulated other
comprehensive income (loss) consists principally of changes in the market value
of certain financial hedges with the implementation of SFAS No. 133 on January
1, 2001.
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.
Accounting for Major Maintenance -
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 statements 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. Provision for major overhaul totaling $1,624,000 for the year ended
December 31, 1999, is included in other operating and maintenance expenses in
the accompany consolidated statements of operations. If the cumulative effect
had been recorded in 1999, then the pro forma effect (unaudited) for 1999 would
have increased net income by approximately $1,323,000.
F-9
New Accounting Pronouncements - In
June 2001, the FASB issued SFAS No. 141, entitled, Business Combinations. This
standard prohibits the use of the pooling-of-interests method of accounting for
business combinations initiated after June 30, 2001 and applies to all business
combinations accounted for under the purchase method that are completed after
June 30, 2001. The Partnership does not expect that implementation of this
standard will have a significant impact on its consolidated financial
statements.
Also in June 2001, the FASB issued SFAS No. 142, entitled, Goodwill and Other
Intangible Assets. This standard eliminates the amortization of goodwill, and
requires goodwill to be reviewed periodically for impairment. This standard also
requires the useful lives of previously recognized intangible assets to be
reassessed and the remaining amortization periods to be adjusted accordingly.
This standard is effective for fiscal years beginning after December 15, 2001,
for all goodwill and other intangible assets recognized on the
Partnership’s consolidated balance sheets at that date, regardless of when
the assets were initially recognized. The Partnership does not expect that
implementation of this standard will have a significant impact on its
consolidated financial statements.
Additionally, in June 2001, the FASB issued SFAS No. 143, entitled, Accounting
for Asset Retirement Obligations. This standard is effective for fiscal years
beginning after June 15, 2002, and provides accounting requirements for asset
retirement obligations associated with tangible long-lived assets. Under the
standard, the asset retirement obligation is recorded at fair value in the
period in which it is incurred by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its present value in each
subsequent period and the capitalized cost is depreciated over the useful life
of the related assets. The Partnership has not yet determined the effects of
this standard on its financial reporting.
In August 2001, the FASB issued SFAS No. 144, entitled, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No.
121, entitled, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of, but retains its fundamental provisions for
recognizing and measuring impairment of long-lived assets to be held and used.
This standard also requires that all long-lived assets to be disposed of by sale
are carried at the lower of carrying amount or fair value less cost to sell, and
that depreciation should cease to be recorded on such assets. SFAS No. 144
standardizes the accounting and presentation requirements for all long-lived
assets to be disposed of by sale, superceding previous guidance for discontinued
operations of business segments. This standard is effective for fiscal years
beginning after December 15, 2001. The Partnership does not expect that the
implementation of this standard will have a significant impact on its
consolidated financial statements.
Reclassifications - Certain
reclassifications have been made in the 2000 and 1999 consolidated financial
statements to conform to the current-year presentation.
3. ACCOUNTING FOR DERIVATIVE CONTRACTS
Currency exchange contracts - The
Partnership has two foreign currency exchange contracts 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.
Effective January 1, 2001, the Partnership began accounting for its foreign
exchange contracts as cash flow hedges and recorded on the consolidated balance
sheets a liability for derivative contracts (Note 2).
F-10
For the years ended December 31, 2001, 2000, and 1999, amounts charged to fuel
costs as a result of losses realized from these contracts totaled approximately
$3,245,000, $2,463,000, and $2,342,000, respectively. The Partnership expects
that net derivative losses of approximately $3,688,000, included in accumulated
other comprehensive loss as of December 31, 2001, will be reclassified into
earnings within the next twelve months.
The schedule below summarizes the activities affecting accumulated other
comprehensive loss from derivative contracts for the year ended December 31,
2001 (in thousands):
Beginning accumulated other comprehensive loss at January 1, 2001 $ (8,968)
Net change of current period hedging transactions gain (loss) (3,412)
Net reclassification to earnings 3,245
--------------------
Ending accumulated other comprehensive loss at December 31, 2001 $ (8,801)
====================
4. PARTNERS’ CAPITAL
The general and limited partners and their respective equity interests are
as follows:
Interest
--------------------------------
Partners Affiliated With Preferred Original
General partners:
JMC Selkirk, Inc. Beale Generating Company 0.09 % 1.00 %
RCM Selkirk GP, Inc.* RCM Holdings, Inc.*** 1.00 -
Limited partners:
JMC Selkirk, Inc. Beale Generating Company 1.95 21.40
PentaGen Investors, L.P. Beale Generating Company 5.25 57.60
Aquila Selkirk, Inc.**** Aquila East Coast Generation, Inc. ***** 13.55 20.00
RCM Holdings, Inc.*** RCM Selkirk LP, 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%.
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 $165,000,000 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
$227,000,000 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):
2002 $ 13,529
2003 17,365
2004 19,587
2005 25,230
2006 31,657
2007 and thereafter 255,396
---------
$ 362,764
=========
The bonds are secured by substantially all of the assets of the Partnership and
are nonrecourse 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, Current Portion of the Major
Maintenance Reserve Fund, Principal Fund, Interest Fund, and the Partnership
Distribution Fund. The Funds that are active and included in long-term
restricted funds in the accompanying consolidated balance sheets are the
Long-Term Portion of 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
(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 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, 2001 and 2000, the balance in the Major Maintenance
Reserve Fund was approximately $4,091,000 and $3,855,000,
respectively.
The Interest and Principal Funds relate primarily to the current debt service on
the outstanding Bonds. The applicable Fund Requirements for the Interest and
Principal Funds are the amounts due and payable on the next semi-annual payment
date. On December 26, 2001 and 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, 2001 and 2000.
F-12
The Fund Requirement for the Debt Service Reserve Fund is an amount equal to the
maximum amount of debt service due in respect of the Bonds outstanding for any
six-month period during the succeeding three-year period. At December 31,
2001 and 2000, the balance in the Debt Service Reserve Fund was approximately
$24,311,000 and $23,978,000, respectively.
The Partnership Distribution Fund has the lowest priority in the fund hierarchy.
Cash distributions to the Partners from this fund 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 available for its use a credit agreement, as amended (“Credit
Agreement”), with a 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 purposes of meeting letters of credit
requirements under various project contracts and for meeting working capital
requirements. The maximum amount available under the Credit Agreement for
working capital purposes is $5,000,000. As of December 31, 2001 and 2000, there
were no amounts drawn or balances outstanding under either the letters of credit
or the working capital arrangement.
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,
2001 and 2000, was approximately $371,402,000 and $400,977,000,
respectively.
Currency Exchange Agreements – The fair value of the currency exchange
agreements is based on current market rates for currency exchange. The fair
value of the currency exchange arrangements was approximately $8,801,000 and
$8,968,000 at December 31, 2001 and 2000, respectively.
7. CONCENTRATIONS OF CREDIT RISK
Credit Risk – Credit risk is the risk of loss the Partnership would
incur if counterparties fail to perform their contractual obligations. The
Partnership primarily conducts business with customers in the energy industry,
such as investor-owned utilities, energy trading companies, financial
institutions, gas production companies and gas transportation companies located
in the United States and Canada. Specifically, the Partnership’s revenues
are primarily concentrated with the following customers: Con Edison, Niagara
Mohawk and the New York Independent System Operator. This concentration of
counterparties may impact the Partnership’s overall exposure to credit risk
in that its counterparties may be similarly affected by changes in economic,
regulatory or other conditions. The Partnership mitigates potential credit
losses in accordance with established credit approval practices and limits by
dealing primarily with creditworthy counterparties (counterparties considered
investment grade or higher).
F-13
8. COMMITMENTS AND CONTINGENCIES
Power Purchase Agreements, Electricity – Prior to July 1, 1998, the
Partnership had a power purchase agreement, as amended, with 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 $4,597,000 and
$5,304,000 in the accompanying consolidated balance sheets at December 31, 2001
and 2000, respectively.
The Partnership also has a power purchase agreement with Con Edison for an
initial term of 20 years that 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.
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.
F-14
On July 21, 1998, the New York Public Service Commission 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, 2001, 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 operating lease agreement with General Electric at no cost to the
Partnership.
The agreement provides General Electric the right of first refusal to purchase
the Facility, subject to certain pricing considerations. Additionally, General
Electric has the right to purchase the boiler facility that produces steam at a
mutually agreed upon price upon termination of the steam sale agreement. The
steam sales agreement may be terminated by the Partnership with a one-year
advanced written notice upon the termination of either Niagara Mohawk or Con
Edison power purchase agreement, whichever is earlier. The steam sales agreement
may also be terminated by General Electric with a two-year advanced written
notice if General Electric’s plant no longer has a requirement for
steam.
The Partnership has entered into various long-term firm commitments with
approximate dollar obligations as follows (in thousands):
2007 and
--------
2002 2003 2004 2005 2006 Thereafter
---- ---- ---- ---- ---- ----------
Fuel Supply and Transportation
Agreements $53,402 $55,121 $56,802 $56,224 $57,506 $413,236
Electric Interconnection and
Transmission Agreements 600 600 600 600 600 4,250
Site Lease 1,000 1,000 1,000 1,000 1,000 7,667
Payment in Lieu of Taxes 3,100 3,300 3,500 3,700 3,800 24,900
Fuel Supply and Transportation Agreements – The Partnership has 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 November 1, 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, 2001, 2000, and 1999, the Partnership purchased gas totaling approximately
$53,848,000, $55,917,000 and $34,209,000, respectively, under these
agreements.
F-15
The Partnership has three firm fuel transportation service agreements for Unit
1, each with a 20-year term commencing November 1, 1992.
The Partnership has three firm fuel transportation service agreements for Unit
2, each with a 20-year term commencing November 1, 1994. Under one of these
agreements, 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 $8,297,000 Canadian
dollars. The Partnership is obligated to reimburse the fuel suppliers for all
costs related to obtaining and maintaining the letters of credit.
Electric Interconnection and Transmission Agreements – The
Partnership constructed an interconnection facility to interconnect the power
output from Unit 1 to Niagara Mohawk’s electric transmission system and has
transferred title of this interconnection 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 to
transmit the power output 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 title to 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 is approximately
$1,000,000.
Payment in Lieu of Taxes Agreement –In October 1992, the Partnership
entered into a PILOT agreement with the Town of Bethlehem Industrial Development
Agency (“IDA”), a corporate governmental agency, which exempts the
Partnership from certain property taxes. The agreement commenced on January 1,
1993, and will terminate on December 31, 2012. PILOT payments are due
semi-annually in equal installments.
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.
F-16
On November 6, 2001, the Partnership received from the New York State Department
of Environmental Conservation (“DEC”) the Facility’s Title V
operating permit endorsed by the DEC on November 2, 2001 (the “Title V
Permit”). The Title V Permit as received by the Partnership contains
conditions that conflict with the Partnership’s existing air permits, and
the Facility’s compliance with these conditions under certain operating
circumstances would be problematic. Further, the Partnership believes that
certain of the conditions contained in the Title V Permit are inconsistent with
the laws and regulations underlying the Title V program and Title V operating
permits issued by the DEC to comparable electric generating facilities in New
York. By letter dated November 12, 2001, the Partnership has filed with the DEC
a request for an adjudicatory hearing to address and resolve the issues
presented by the Title V Permit, and the terms and conditions of the Title V
Permit will be stayed pending a final DEC decision on the appeal. At this time
it is too early for the Partnership to assess the likely outcome of the
adjudicatory hearing and the impact on the Facility.
9. 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, 2001, 2000, and 1999, expenses incurred for
services provided by JMCS I Management totaled approximately $3,601,000
$3,569,000, and $2,027,000, respectively. The cost of services provided by JMCS
I Management are included in administrative services – affiliates in the
accompanying consolidated statements of operations.
The Partnership purchases and sells gas to PG&E Energy Trading – Gas
Corporation, Pittsfield Generating Company, L.P. and MASSPOWER, affiliates of
JMC Selkirk, Inc., at fair value. Gas purchased from affiliates of JMC Selkirk,
Inc., totaled approximately $7,572,000, $559,000, and $140,000, respectively, in
2001, 2000, and 1999, and gas sold to affiliates of JMC Selkirk, Inc. totaled
approximately $16,782,000, $3,806,000, and $453,000, 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, 2001, 2000, and
1999, sales of energy, capacity and other services totaled approximately
$3,878,000, $14,888,000, and $5,515,000, 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,
2001, 2000, and 1999, firm fuel transportation services totaled approximately
$7,741,000, $8,227,000, and $7,994,000, respectively. These services are
recorded as fuel costs in the accompanying consolidated statements of
operations.
* * * * * *
F-17
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
3.7 Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership
of the Partnership, dated as of November 15, 2001
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)
42
10.1 Credit Facilities
10.1.1(1) Credit Bank Working Capital and Reimbursement Agreement, dated as of May 1, 1994,
among the Partnership, The Chase Manhattan Bank, N.A. ("Chase"), as Agent, and the
other Credit Banks identified therein
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
43
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(20) 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
44
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
45
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")
46
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
47
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
48
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
49
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
50
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
51
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
99.4(15) Press Release of the Partnership, dated August 31, 1998
52
- -------------------
(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.
53
(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.
(20) Incorporated herein by reference to the Registrant’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 filed March 30, 2001.
54
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 29, 2002 /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 29, 2002
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 29, 2002
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 29, 2002
- ------------------- Chief Financial Officer
John R. Cooper
/s/ ERNEST K. HAUSER Senior Vice President March 29, 2002
- ---------------------
Ernest K. Hauser
/s/ DAVID N. BASSETT Treasurer March 29, 2002
- ---------------------
David N. Bassett
55
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.
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.
56
SELKIRK COGEN FUNDING
CORPORATION
Date: March 29, 2002 /s/ JOHN R. COOPER
----------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
Signature Title Date
--------- ----- ----
/s/ P. CHRISMAN IRIBE President and Director March 29, 2002
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 29, 2002
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 29, 2002
- ------------------- Chief Financial Officer
John R. Cooper
/s/ ERNEST K. HAUSER Senior Vice President March 29, 2002
- ---------------------
Ernest K. Hauser
/s/ DAVID N. BASSETT Treasurer March 29, 2002
- ---------------------
David N. Bassett