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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, 2002
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.)
7600 Wisconsins Avenue (Mailing Address: 7500 Old Georgetown Road), Bethesda, Maryland 20814
(Address of principal executive offices, including zip code)
(301) 280-6800
(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
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes __ No X
As of March 28, 2003, 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
Business Overview and Structure.............................................. 1
The Facility and Certain Project Contracts................................... 5
Fuel Management.............................................................. 10
Customers / Competition...................................................... 12
Seasonality.................................................................. 13
Regulations and Environmental Matters........................................ 13
Employees.................................................................... 15
Item 2. Properties................................................................... 15
Item 3. Legal Proceedings............................................................ 15
Item 4. Submission of Matters to a Vote of Security Holders.......................... 15
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................................ 16
Item 6. Selected Financial Data...................................................... 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................................ 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ................... 33
Item 8. Financial Statements and Supplementary Data................................... 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.......................................... 33
PART III
Item 10. Directors and Executive Officers of the Funding Corporation
and the Managing General Partner............................................. 34
Item 11. Executive and Board Compensation and Benefits................................. 35
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................................. 36
Item 13. Certain Relationships and Related Transactions................................ 37
Item 14. Controls and Procedures....................................................... 37
PART IV
Item 15. Financial Statements, Exhibits and Reports on Form 8-K........................ 39
SIGNATURES AND CERTIFICATIONS.......................................................... 51
i
PART I
ITEM 1. BUSINESS
Business Overview and Structure
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 wholly
owned subsidiary of the Partnership, was organized in April 1994 as a Delaware
corporation 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 7600 Wisconsin Avenue (Mailing Address: 7500 Old Georgetown
Road), Bethesda, Maryland 20814. The telephone number is (301) 280-6800.
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"). 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"), Aquila Selkirk, Inc.
("Aquila Selkirk", formerly EI Selkirk, Inc.) and RCM Selkirk, LP, Inc. ("RCM
Selkirk LP").
1
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.
JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating
Company ("Beale") 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, the parent company of Pacific Gas and Electric Company
(the "Utility").
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 NEG.
Investors is a Delaware limited partnership consisting of JMCS I Holdings,
Inc., JMC Selkirk (each an affiliate of Beale), and FPP Selkirk LLC ("FPP
Selkirk", formerly TPC Generating, Inc.).
RCM Selkirk GP and RCM Selkirk LP are each affiliates of RCM Holdings, Inc.
("RCM").
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.).
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").
2
The Bonds, the Partnership Loans and the Guarantee are not guaranteed by,
or otherwise obligations of, the Partners, Beale, FPP Selkirk, NEG, 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.
Relationship with PG&E Corporation and NEG
In December 2000, and January and February 2001, PG&E Corporation and
NEG completed a corporate restructuring of NEG that 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.
On April 6, 2001, the Utility filed a voluntary petition for relief under
the provisions of Chapter 11 of the U.S. Bankruptcy Code ("Bankruptcy Code") in
the United States Bankruptcy Court for the Northern District of California
("Bankruptcy Court"). Pursuant to the 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. The Utility and PG&E Corporation have jointly filed a plan of
reorganization that entails separating the Utility into four distinct
businesses. The proposed plan of reorganization does not directly affect NEG or
any of its subsidiaries. The Managing General Partner believes that NEG and its
direct and indirect subsidiaries, including JMC Selkirk, Investors, and the
Partnership, would not be substantively consolidated with PG&E Corporation
in any insolvency or bankruptcy proceeding involving PG&E Corporation or the
Utility.
As a result of the sustained downturn in the power industry, NEG and
certain of its affiliates have experienced a financial downturn, which caused
the major credit rating agencies to downgrade NEG and certain of its affiliates'
credit ratings to below investment grade. The credit rating agency action has
had no material impact on the financial condition or results of operations of
the Partnership.
3
On October 8, 2002, Moody's Investor Services ("Moody's") stated that in
conjunction with the downgrade of NEG it had placed the Partnership's debt under
review for possible downgrade. On October 15, 2002, Standard and Poor's ("S&P")
stated that the recent downgrade of NEG will not have an affect on the rating of
the Partnership's debt at this time. S&P's rating of the Partnership's debt is
"BBB-". On November 5, 2002, Moody's issued an opinion update changing the
rating outlook of the Partnership's debt to "under review for possible
downgrade" from "stable" for the Partnership's debt due in 2007 and "negative
outlook" for the Partnership's debt due in 2012. Moody's rating of the
Partnership's debt is "Baa3". A downgrade of the credit ratings of the
Partnership's debt due in 2007 or 2012 by S&P or Moody's (or both) would not be
an event of default under any of the Partnership's debt agreements and material
project contracts or otherwise result in an adverse change to any material term
of such agreements and contracts.
NEG and certain affiliates are currently in default under various debt
agreements and guaranteed equity commitments. NEG, its subsidiaries and their
lenders are engaged in discussions to restructure NEG's debt obligations and
such other commitments. None of JMC Selkirk, Investors or the Partnership are
parties to such debt agreements and guaranteed equity commitments or
participants in such discussions. NEG and its subsidiaries are continuing to
review opportunities to abandon, sell, or transfer certain assets, and have
significantly reduced their energy trading operations in an ongoing effort to
raise cash and reduce debt, whether through negotiation with lenders or
otherwise.
If the lenders exercise their default remedies or if the financial
commitments are not restructured, NEG and the affected affiliates may be
compelled to seek protection under or be forced into a proceeding under the U.S.
Bankruptcy Code.
NEG owns an indirect interest in the Partnership, and through its indirect,
wholly owned subsidiaries, JMC Selkirk and JMCS I Management, manages the
Partnership. The Partnership cannot be certain that an insolvency or bankruptcy
involving NEG or any of its subsidiaries would not affect NEG's ownership
arrangements with respect to the Partnership or the ability of JMC Selkirk or
JMCS I Management to manage the Partnership. The Partnership Agreement provides
certain management rights to RCM Selkirk GP in the event that JMC Selkirk were
to be included in a bankruptcy involving NEG, including (i) the removal of JMC
Selkirk as the managing general partner, (ii) the appointment of itself as the
successor managing general partner, and (iii) the termination of the
administrative services agreement with JMCS I Management and subsequent
appointment of a RCM Selkirk GP affiliate as the project management firm.
Enforcement of these rights by RCM Selkirk GP could, however, be delayed or
impeded as a result of any bankruptcy proceeding involving JMC Selkirk.
Moreover, the bankruptcy of any partner of the Partnership would be an event of
default under the Partnership's Credit Agreement. Currently, the Partnership has
contingent reimbursement obligations arising under letters of credit issued
under this Credit Agreement in the amount of approximately $2.5 million, which
the Partnership believes could be secured with cash collateral financed with
cash flows from operations. (See "Credit Agreement", included in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations below).
4
The Facility and Certain Project Contracts
The Facility
The Facility is located on a 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, the New York Independent System
Operator ("NY ISO") and PG&E Energy Trading - Power, L.P. ("PG&E Energy Trading
- - Power") 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. Electric
sales to Niagara Mohawk for the year ended December 31, 2002 accounted for 15.3%
of total project revenues, compared to 16.5% in 2001 and 18.7% in 2000.
5
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).
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
NY ISO commenced operations for each of eleven regions and at each generator
interconnection within New York State. The NY 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.
The Amended and Restated Niagara Mohawk Power Purchase Agreement transfers
dispatch decision-making authority from Niagara Mohawk to the Partnership. In
effect, Unit 1 will operate on a "merchant-like" basis, whereby the Partnership
will have the ability and flexibility to dispatch Unit 1 based on current market
conditions. 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.
6
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.
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 NY 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.
7
Con Edison
8
General Electric
9
Unit 1 Gas Supply and Transportation
10
Unit 1 and Unit 2 have the capability to operate on No. 2 fuel oil and are
designed 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.
11
Customers/Competition
12
Seasonality
13
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.
14
Employees
15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
16
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
18
Legislative and Regulatory Matters
19
Relationship with PG&E Corporation and NEG
20
certain management rights to RCM Selkirk GP in the event that JMC Selkirk were
to be included in a bankruptcy involving NEG, including (i) the removal of JMC
Selkirk as the managing general partner, (ii) the appointment of itself as the
successor managing general partner, and (iii) the termination of the
administrative services agreement with JMCS I Management and subsequent
appointment of a RCM Selkirk GP affiliate as the project management firm.
Enforcement of these rights by RCM Selkirk GP could, however, be delayed or
impeded as a result of any bankruptcy proceeding involving JMC Selkirk.
Moreover, the bankruptcy of any partner of the Partnership would be an event of
default under the Partnership's Credit Agreement. Currently, the Partnership has
contingent reimbursement obligations arising under letters of credit issued
under this Credit Agreement in the amount of approximately $2.5 million, which
the Partnership believes could be secured with cash collateral financed with
cash flows from operations. (See "Credit Agreement" below)
21
Results of Operations
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.
22
The following highlights the principal changes in operating revenues and operating expenses.
23
The year ended 2000 included a net gain for the cumulative effect of a
change in accounting principle of $7.9 million. The cumulative effect was based
on the Partnership changing its method of accounting for major maintenance and
overhaul costs as of January 1, 2000 to expensing the cost of major maintenance
and overhauls 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.
24
The debt service coverage ratio for 2002 calculated pursuant to the
Indenture was 1.75:1.
25
Funds
26
Commitments
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.
27
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.
28
Market Risk
29
Credit Risk
30
Accounting Principles Issued But Not Yet Adopted
31
Regulations and Environmental Matters
32
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
33
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING
P. Chrisman Iribe is President and Chief Operating 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, 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.
34
Thomas E. Legro is Vice President and Controller of PG&E National Energy
Group Company, an affiliate of the Partnership, and has been with PG&E National
Energy Group Company since July 2001. From January 1994 to June 2001, Mr. Legro
was Vice President and Controller of Edison Mission Energy. Mr. Legro was
elected Vice President and Controller of both the Funding Corporation and the
Managing General Partner on April 1, 2002. Mr. Legro was elected Chief
Accounting Officer and Director of both the Funding Corporation and the Managing
General Partner on February 1, 2003.
35
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
* Formerly EI Selkirk, Inc.
36
(3) Beale 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 (89.1%) and Cogentrix (10.9%). NEG is the indirect
beneficial owner of PG&E Generating Power. Cogentrix is beneficially owned
by Cogentrix Energy, Inc.
37
Changes in Internal Controls
38
PART IV
ITEM 15. FINANCIAL STATEMENTS, EXHIBITS AND REPORTS ON FORM 8-K
39
INDEPENDENT AUDITORS' REPORT
F-1
F-2
F-3
F-4
F-5
SELKIRK COGEN PARTNERS, L.P.
F-6
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.
F-7
NEG and certain affiliates are currently in default under various debt
agreements and guaranteed equity commitments. NEG, its subsidiaries and their
lenders are engaged in discussions to restructure NEG’s debt obligations
and such other commitments. None of JMC Selkirk, Investors or the Partnership
are parties to such debt agreements and guaranteed equity commitments or
participants in such discussions. NEG and its subsidiaries are continuing to
review opportunities to abandon, sell, or transfer certain assets, and have
significantly reduced their energy trading operations in an ongoing effort to
raise cash and reduce debt, whether through negotiation with lenders or
otherwise.
F-8
On April 1, 2002, the Partnership implemented two interpretations issued by the
Financial Accounting Standard Board’s (“FASB”) Derivatives
Implementation Group (“DIG”). DIG Issues C15 and C16 changed the
definition of normal purchases and sales included in SFAS No. 133. Previously,
certain derivative commodity contracts for the physical delivery of purchase and
sale quantities transacted in the normal course of business were exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exemption, and
thus were not marked-to-market and reflected on the balance sheet like other
derivatives. Instead, these contracts were recorded on an accrual basis.
F-9
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.
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.
F-10
Adoption of New Accounting Pronouncements - In June 2001, the FASB issued
SFAS No. 142, Goodwill and Other Intangible Assets. This statement
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 statement 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.
This statement was adopted on January 1, 2002, and did not have an impact on the
Partnership’s consolidated financial statements.
F-11
3. ACCOUNTING FOR DERIVATIVE CONTRACTS
Peak shaving arrangements - The Partnership enters into peak shaving
arrangements whereby it 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. Revenues
from peak shaving arrangements for the year ended December 31, 2002 was
approximately $446,000 as compared to $744,000 in 2001. On July 1, 2001, the
Partnership determined peak shaving arrangements were no longer exempt from the
requirements of SFAS No. 133 and recorded a loss of approximately $519,000
reflecting the cumulative effect of a change in accounting principle. Changes in
the fair value of peak shaving arrangements are recorded on the consolidated
statements of operations as an unrealized gain or loss on derivative contracts.
The unrealized loss on derivative contracts for the year ended December 31, 2002
was approximately $446,000, compared to an unrealized gain on derivative
contracts of approximately $965,000 in 2001.
F-12
4. PARTNERS' CAPITAL
F-13
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.
F-14
The Partnership does not expect the Credit Agreement to be renewed in August
2003 and is seeking to find a lender to replace the existing Credit Agreement.
If the Partnership is unable to replace the existing Credit Agreement, it may be
required to secure its current letters of credit and any requests for additional
assurances with cash collateral financed with cash flows from operations. The
Partnership believes it will have sufficient cash flows from operations to
secure its letters of credit and to meet its working capital requirements.
F-15
8. COMMITMENTS AND CONTINGENCIES
F-16
The Partnership has entered into various long-term firm commitments with
approximate dollar obligations as follows (in thousands):
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.
F-17
Long Term Parts Agreement – The Partnership has a long-term parts
agreement with GE International, Inc. to purchase a certain dollar amount (the
“Contract Value”) of spare parts during the course of the contract.
The terms of the agreement are effective through the end of 2007. As of December
31, 2002, approximately $6,885,000 of the Contract Value remains outstanding and
must be purchased by the end of the contract period.
F-18
The Partnership purchases from and sells gas to PG&E Energy Trading –
Gas, PG&E Energy Trading – Canada, Pittsfield Generating Company, L.P.
(“Pittsfield Generating”), and MASSPOWER, affiliates of JMC Selkirk,
Inc., at fair value. Gas purchases are recorded as fuel costs and sales of gas
are recorded as fuel revenues in the accompanying consolidated statements of
operations. As of December 31, 2002, the net amount due from PG&E Energy
Trading – Gas was approximately $160,000 and the net amount due from
PG&E Energy Trading – Canada was approximately $21,000. The Partnership
believes there are sufficient counterparties available with which to undertake
transactions in the natural gas market and therefore, reductions in NEG’s
energy trading operations will not have a material impact on the results of
operations of the Partnership. (Note 1)
In May 1996, the Partnership entered into an enabling agreement with PG&E
Energy Trading – Power to purchase and sell electric capacity, electric
energy, and other services. Sales of energy, capacity and other services for the
year ended December 31, 2002 totaled approximately $2,264,000, compared to
approximately $3,878,000 in 2001 and approximately $14,888,000 in 2000. There
was no amount due from PG&E Energy Trading – Power at December 31,
2002.
* * * * * *
40
41
42
43
44
45
46
47
48
49
(1) Incorporated by reference to the Registrant's Registration Statement on Form
S-1 filed September 1, 1994, as amended (File No. 33-83618).
50
51
52
53
54
55
56
---------------------------------------------------------------------------------
Contract Annual Contract
Contract Year ended Volume Quantity
Year June 30, MWh MW
---------------------------------------------------------------------------------
1 1999 325,400 37.146
2 2000 331,000 37.785
3 2001 375,900 42.911
4 2002 417,500 47.660
5 2003 419,500 47.888
6 2004 442,000 50.457
7 2005 451,700 51.564
8 2006 461,300 52.660
9 2007 473,400 54.041
10 2008 485,200 55.388
---------------------------------------------------------------------------------
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. Electric
sales to Con Edison for the year ended December 31, 2002 accounted for 63.0% of
total project revenues, compared to 65.2% in 2001 and 61.5% in 2000.
New York Independent System Operator
The NY ISO commenced operation on November 18, 1999 and took formal control
of the New York wholesale electric power system on December 1, 1999. The NY 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 NY ISO in the NY ISO-administered markets, or bilateral transactions
between participants in the New York wholesale market. PG&E Energy Trading -
Power and the Partnership are active participants in these markets. To enter
into energy transactions with the NY ISO, the Partnership entered into a
services agreement under the New York ISO Market Administration and Control
Services Tariff (the "Services Agreement") with the NY ISO on October 12, 1999.
Sales to the NY ISO for the year ended December 31, 2002 accounted for 11.0% of
total project revenues, compared to 8.1% in 2001 and 0.1% in 2000.
PG&E Energy Trading-Power
Through an enabling agreement (the "Enabling Agreement") with PG&E
Energy Trading - Power, an indirect, wholly owned subsidiary of NEG and an
affiliate of JMC Selkirk, the Partnership may sell excess capacity and energy
generated from Units 1 and 2 and other energy-related products to PG&E
Energy Trading - Power. 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 - Power. The Enabling Agreement had
previously been extended through May 31, 2002 and both parties approved renewal
of the Enabling Agreement through May 31, 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. Sales to PG&E Energy Trading - Power for the year ended December
31, 2002 accounted for 1.0% of total project revenues, compared to 1.9% in 2001
and 6.4% in 2000. The Partnership believes that reductions in NEG's energy
trading operations will not have a material impact on the results of operations
of the Partnership. (See "Relationship with PG&E Corporation and NEG"
above)
Pursuant to a steam sales agreement with General Electric (the "Steam Sales
Agreement"), the Partnership is obligated to sell up to 400,000 lbs/hr of the
thermal output of Unit 1 and Unit 2 for use as process steam at the GE Plant
adjacent to the Facility for a term extending 20 years from the date of
commercial operations of Unit 2. The Partnership charges General Electric a
nominal price for steam delivered to General Electric in an amount up to the
annual equivalent of 160,000 lbs/hr during each hour in which the GE Plant is in
production (the "Discounted Quantity"). Steam sales in excess of the Discounted
Quantity are priced at General Electric's avoided variable direct cost, subject
to an "annual true-up" to ensure that General Electric receives the annual
equivalent of the Discounted Quantity at nominal pricing.
Pursuant to the Steam Sales Agreement, General Electric may implement
productivity or energy efficiency projects in its manufacturing processes,
including projects involving the production of steam within the GE Plant
commencing in 1996. General Electric implemented an energy efficiency project in
1997 that 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. Sales to General Electric for the year ended December 31, 2002
accounted for 0.1% of total project revenues, compared to 0.0% in 2001 and 1.1%
in 2000.
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.
Fuel Management
The Project Management Firm manages the Facility's fuel supply and
transportation 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 spot market natural
gas supplies utilizing the Partnership's firm gas transportation. 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. Fuel revenues, accounted for 9.6% of total
project revenues for the year ended December 31, 2002, compared to 8.3% in 2001
and 12.2% in 2000. The majority of fuel revenues during the years ended December
31, 2002 and 2001 resulted from sales with PG&E Energy Trading - Gas
Corporation ("PG&E Energy Trading - Gas"), an indirect, wholly owned
subsidiary of NEG and an affiliate of JMC Selkirk. The Partnership believes
there are sufficient counterparties available with which to undertake
transactions in the natural gas market and therefore, reductions in NEG's energy
trading operations will not have a material impact on the results of operations
of the Partnership. (See "Relationship with PG&E Corporation and NEG"
above)
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 - Power, an affiliate of JMC Selkirk, is an
indirect, wholly owned subsidiary of NEG, and is engaged in buying and selling
energy and energy-related products to power marketers, industrials, utilities
and municipalities. PG&E Energy Trading - Power trades with United States
and Canadian counterparties.
The NY 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.
PG&E Energy Trading - Gas, an affiliate of JMC Selkirk, is an indirect,
wholly owned subsidiary of NEG, and is engaged in buying and selling various
fuels to fuel marketers, industrials, utilities and municipalities. PG&E
Energy Trading - Gas trades with United States and Canadian
counterparties.
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 each 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.
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.
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.
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. The DEC has confirmed that the terms and conditions of the Title V
Permit are stayed pending a final DEC decision on the appeal. Since November 12,
2001, the Partnership and DEC staff have engaged in negotiations regarding the
Title V Permit. At this time, the Partnership cannot assess whether a settlement
can be achieved, the likely outcome of the adjudicatory hearing if no settlement
is achieved, or the impact on the Facility.
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 employees at the Facility and support personnel from its Bethesda, Maryland
and Boston, Massachusetts offices.
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 29 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.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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
The following tables present a summary of the Partnership's historical
financial data and should be read in conjunction with Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations
included herein. Certain reclassifications have been made to the selected
financial data and supplementary financial information set forth below to
conform to the current-year presentation.
Statement of Operations Data (in thousands):
Year Ended December 31,
---------------------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- --------------
Operating revenues $227,578 $229,725 $234,377 $177,468 $172,739
Cost of revenues 153,359 154,638 163,406 117,331 119,240
Other operating expenses 4,252 4,292 4,396 3,401 3,967
----------- ----------- ----------- ----------- --------------
Operating income 69,967 70,795 66,575 56,736 49,532
Net interest expense 32,017 31,911 32,027 32,839 33,211
----------- ----------- ----------- ----------- --------------
Income before cumulative effect 37,950 38,884 34,548 23,897 16,321
of a change in accounting
principle
Cumulative effect of a change
in accounting principle --- (519) 7,866 --- ---
----------- ----------- ----------- ----------- --------------
Net income $37,950 $38,365 $42,414 $23,897 $16,321
=========== =========== =========== =========== ==============
Balance Sheet Data (in thousands):
December 31,
------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
Plant and equipment, net $263,003 $273,913 $285,324 $297,034 $308,999
Total assets 339,955 347,963 358,942 367,087 373,877
Long-term bonds,
net of current portion 331,870 349,235 362,764 373,826 381,133
Partners' deficits (45,713) (55,783) (49,646) (50,832) (46,810)
Supplementary Financial Information
The following is a summary of the quarterly results of operations (unaudited) for the years ended December 31, 2002, 2001
and 2000 (in thousands).
Three Months Ended
----------------------------------------------------------
Mar 31 Jun 30 Sep 30 Dec 31 TOTAL
----------- ----------- ------------ ------------ ----------------
2002
Operating revenues $52,955 $53,424 $58,276 $62,923 $227,578
Gross Profit 18,702 11,731 21,062 22,724 74,219
Net Income 9,434 2,702 11,865 13,949 37,950
2001
Operating revenues $66,473 $57,677 $53,124 $52,451 $229,725
Gross Profit 19,565 14,955 19,731 20,836 75,087
Income before cumulative effect
of a change in accounting
principle 10,616 5,860 10,604 11,804 38,884
Cumulative effect of a change
in accounting principle --- --- (519) --- (519)
Net Income 10,616 5,860 10,085 11,804 38,365
2000
Operating revenues $60,585 $52,270 $56,763 $64,759 $234,377
Gross Profit 19,820 14,326 19,017 17,808 70,971
Income before cumulative effect
of a change in accounting
principle 10,673 5,119 9,679 9,077 34,548
Cumulative effect of a change
in accounting principle 7,866 --- --- --- 7,866
Net Income 18,539 5,119 9,679 9,077 42,414
CONDITION AND RESULTS OF OPERATIONS
Cautionary Statement Regarding Forward-Looking Statements
The information in this Annual Report on Form 10-K includes forward-looking
statements about the future that are necessarily subject to various risks and
uncertainties. Use of words like "anticipate," "estimate," "intend," "project,"
"plan," "expect," "will," "believe," "could," and similar expressions help
identify forward-looking statements. These statements are based on current
expectations and assumptions which the Partnership believes are reasonable and
on information currently available to the Partnership. Actual results could
differ materially from those contemplated by the forward-looking statements.
Although the Partnership believes that the expectations reflected in the
forward-looking statements are reasonable, future results, events, levels of
activity, performance or achievements cannot be guaranteed. Although the
Partnership is not able to predict all the factors that may affect future
results, some of the factors that could cause future results to differ
materially from those expressed or implied by the forward-looking statements
include:
Operational Risks
The Partnership's future results of operation and financial condition will
be affected by 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.
Potential Collateral Requirements
The Partnership's future results of operations and financial condition may
be affected if its credit agreement is not renewed or replaced, which would
require the Partnership to secure its current letters of credit and any requests
for additional assurances with cash collateral.
Accounting and Risk Management
The Partnership's future results of operation and financial condition may
be affected by the effect of new accounting pronouncements; changes in critical
accounting policies or estimates; the effectiveness of the Partnership's risk
management policies and procedures; the ability of the Partnership's
counterparties to satisfy their financial commitments to the Partnership and the
impact of counterparties' nonperformance on the Partnership's liquidity
position; and heightened rating agency criteria and the impact of changes in the
Partnership's credit ratings.
The Partnership's business may be affected by legislative or regulatory
changes affecting the electric and natural gas industries in the United States,
including the pace and extent of efforts to restructure the electric and natural
gas industries; heightened regulatory and enforcement agency focus on the energy
business with the potential for changes in industry regulations and in the
treatment of the Partnership by state and federal agencies; changes in or
application of federal, state, and local laws and regulations to which the
Partnership is subject; and changes in or application of Canadian laws,
regulations, and policies which may impact the Partnership.
Litigation and Environmental Matters
The Partnership's future results of operation and financial condition may
be affected by the effect of compliance with existing and future environmental
and safety laws, regulations, and policies, the cost of which could be
significant; the outcome of future litigation and environmental matters; and the
outcome of the negotiations with the DEC regarding the Facility's Title V
operating permit as described in "Regulations and Environmental Matters" below.
Overview
The Partnership owns a natural gas-fired, combined-cycle cogeneration
facility consisting of two units designed to operate independently for
electrical generation, but thermally integrated for steam generation. Revenues
are derived primarily from sales of electricity and, to a lesser extent, from
sales of steam and natural gas. Sales of natural gas typically occur when a unit
is dispatched off-line or at less than full capacity ("Gas Resales"). In
addition, sales of natural gas may also occur when 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 ("Gas
Optimizations"). During the first quarter of 2003, natural gas resale prices and
the price of natural gas under the firm gas supply contracts have been higher
than prices during the first quarter of 2002. The Partnership can not predict
whether such prices will remain above 2002 levels for the balance of 2003.
The Facility will typically be scheduled on an economic basis, which takes
into account the variable cost of electricity to be delivered by each unit
compared to the variable cost of electricity available to the purchaser from
other sources. At times, a unit will be dispatched off-line to perform scheduled
maintenance. Differences in the timing and scope of scheduled maintenance can
have a significant impact on revenues and the cost of revenues. The Facility has
scheduled four weeks of non-major maintenance outages during 2003.
In December 2000, and January and February 2001, PG&E Corporation and NEG
completed a corporate restructuring of NEG that 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.
On April 6, 2001, the Utility filed a voluntary petition for relief under
the provisions of Chapter 11 of the U.S. Bankruptcy Code ("Bankruptcy Code") in
the United States Bankruptcy Court for the Northern District of California
("Bankruptcy Court"). Pursuant to the 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. The Utility and PG&E Corporation have jointly filed a plan of
reorganization that entails separating the Utility into four distinct
businesses. The proposed plan of reorganization does not directly affect NEG or
any of its subsidiaries. The Managing General Partner believes that NEG and its
direct and indirect subsidiaries, including JMC Selkirk, Investors, and the
Partnership, would not be substantively consolidated with PG&E Corporation in
any insolvency or bankruptcy proceeding involving PG&E Corporation or the
Utility.
As a result of the sustained downturn in the power industry, NEG and
certain of its affiliates have experienced a financial downturn, which caused
the major credit rating agencies to downgrade NEG and certain of its affiliates'
credit ratings to below investment grade. The credit rating agency action has
had no material impact on the financial condition or results of operations of
the Partnership. (See "Credit Ratings" below)
NEG and certain affiliates are currently in default under various debt
agreements and guaranteed equity commitments. NEG, its subsidiaries and their
lenders are engaged in discussions to restructure NEG's debt obligations and
such other commitments. None of JMC Selkirk, Investors or the Partnership are
parties to such debt agreements and guaranteed equity commitments or
participants in such discussions. NEG and its subsidiaries are continuing to
review opportunities to abandon, sell, or transfer certain assets, and have
significantly reduced their energy trading operations in an ongoing effort to
raise cash and reduce debt, whether through negotiation with lenders or
otherwise.
If the lenders exercise their default remedies or if the financial
commitments are not restructured, NEG and the affected affiliates may be
compelled to seek protection under or be forced into a proceeding under the U.S.
Bankruptcy Code.
NEG owns an indirect interest in the Partnership, and through its indirect,
wholly owned subsidiaries, JMC Selkirk and JMCS I Management, manages the
Partnership. The Partnership cannot be certain that an insolvency or bankruptcy
involving NEG or any of its subsidiaries would not affect NEG's ownership
arrangements with respect to the Partnership or the ability of JMC Selkirk or
JMCS I Management to manage the Partnership. The Partnership Agreement provides
This Management's Discussion and Analysis of Financial Condition and
Results of Operations should be read in conjunction with the Partnership's
consolidated financial statements and notes to the consolidated financial
statements included herein.
The following table sets forth operating revenue and related data for the years
ended December 31, 2002, 2001 and 2000 (dollars and volumes in millions).
Year Ended December 31,
---------------------------------------------------------------------------------
2002 2001 2000
------------------------ ----------------------- -----------------------
Volume Dollars Volume Dollars Volume Dollars
---------- --------- ---------- --------- ---------
Dispatch factor:
- ----------------
Unit 1 95.6% 77.6% 95.7%
Unit 2 88.9% 92.2% 87.9%
Capacity factor:
- ----------------
Unit 1 91.7% 73.2% 88.6%
Unit 2 82.1% 87.8% 78.9%
Electric and steam revenues:
- ----------------------------
Unit 1 (Kwh) 641.4 $60.3 510.5 $59.2 617.1 $58.9
Unit 2 (Kwh) 1,904.8 145.2 2,046.0 151.3 1,835.8 144.0
Steam (lbs) 1,426.1 0.2 1,401.6 --- 1,796.6 2.6
--------- --------- ---------
Total electric and 205.7 210.5 205.5
steam revenues
Fuel revenues:
- --------------
Gas resales (mmbtu) 3.1 10.7 2.9 15.6 3.6 15.2
Gas optimizations (mmbtu) 3.0 10.8 0.8 2.9 3.6 11.5
Peak shaving
arrangements (mmbtu) --- 0.4 --- 0.7 0.2 2.1
--------- --------- ---------
Total fuel revenues 21.9 19.2 28.8
--------- --------- ---------
Total operating revenues $227.6 $229.7 $234.3
========= ========= =========
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.
Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001
Overall Results
Net income was $38.0 million in 2002, a decrease of $0.4 million from 2001.
Operating Revenues
Operating revenues were $227.6 million in 2002, a decrease of $2.1 million
from 2001. This decrease was primarily due to lower Unit 2 electric revenues,
partially offset by higher fuel revenues. Unit 2 electric revenues decreased by
$6.1 million in 2002 primarily due to lower fuel index pricing in the Con Edison
contract price for delivered energy and lower volumes of delivered energy
resulting from scheduled major maintenance outages, which occurred in the first
(four weeks) and second (six weeks) quarters of 2002. Fuel revenues increased by
$2.7 million in 2002 primarily due to higher volumes of gas optimizations,
partially offset by lower natural gas resale prices.
Cost of Revenues
The cost of revenues was $153.4 million in 2002, a decrease of $1.3 million
from 2001. This decrease was primarily due to lower fuel and transmission costs;
partially offset by higher other operating and maintenance costs. Fuel and
transmission costs decreased by $8.8 million in 2002 primarily due to the lower
price for natural gas under the firm gas supply contracts, partially offset by
higher volumes of gas optimizations. Other operating and maintenance costs
increased by $6.1 million in 2002 primarily due to the scheduled major
maintenance outages on Unit 2.
Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000
Overall Results
Net income was $38.4 million in 2001, a decrease of $4.0 million from 2000.
This decrease is primarily due to the Partnership recording in 2000 a net gain
for the cumulative effect of a change in accounting principle of $7.9 million,
partially offset by higher Unit 2 electric revenues in 2001.
The year ended 2001 included a net loss for the cumulative effect of a
change in accounting principle of $0.5 million. The cumulative effect was based
on the Partnership's adoption as of July 1, 2001, of Derivative Implementation
Group ("DIG") Interpretation No. C10, reflecting the mark-to-market value of
certain gas contracts that had previously been accounted for under the accrual
basis as normal purchases and sales.
The following highlights the principal changes in operating revenues and
operating expenses.
Operating Revenues
Operating revenues were $229.7 million in 2001, a decrease of $4.6 million
from 2000. This decrease is primarily due to lower fuel revenues and lower steam
revenues, partially offset by higher Unit 2 electric revenues. Fuel revenues
decreased by $9.6 million due to lower volumes of gas optimizations. Steam
revenues decreased by $2.6 million primarily due to lower volumes of delivered
steam. Unit 2 electric revenues increased by $7.3 million in 2001 primarily due
to higher Con Edison capacity payments and higher volumes of delivered energy.
Cost of Revenue
The cost of revenues was $154.6 million in 2001, a decrease of $8.8 million
from 2000. This decrease is primarily due to lower fuel and transmission costs,
partially offset by higher other operating and maintenance costs. Fuel and
transmission costs decreased by $9.2 million in 2001 primarily due to lower
volumes of gas optimizations and lower volumes of gas purchased under the Unit 1
firm gas supply contract resulting from the scheduled major maintenance outage
on Unit 1, which occurred the second (seven weeks) quarter of 2001. Other
operating and maintenance costs increased by $1.4 million in 2001 primarily due
to the scheduled major maintenance outage on Unit 1.
Liquidity and Capital Resources
Net cash provided by operating activities in 2002 was $47.3 million as
compared to $49.6 million in 2001. 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 in 2002 was $2.1 million as compared
to $1.2 million in 2001. Net cash flows used in investing activities primarily
represent net additions to plant and equipment.
Net cash used in financing activities in 2002 was $47.0 million as compared
to $47.1 million in 2001. 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 in 2002 and 2001 primarily represent deposits of
monies into the Interest, Principal and Debt Service Reserve Funds, cash
distributions to Partners and the semi-annual payments of principal and interest
on long-term debt.
Credit Ratings
On October 8, 2002, Moody's stated that in conjunction with the downgrade
of NEG, it had placed the Partnership's debt under review for possible
downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG
will not have an affect on the rating of the Partnership's debt at this time.
S&P's rating of the Partnership's debt is "BBB-". On November 5, 2002,
Moody's issued an opinion update changing the rating outlook of the
Partnership's debt to "under review for possible downgrade" from "stable" for
the Partnership's debt due in 2007 and "negative outlook" for the Partnership's
debt due in 2012. Moody's rating of the Partnership's debt is "Baa3". A
downgrade of the credit ratings of the Partnership's debt due in 2007 or 2012 by
S&P or Moody's (or both) would not be an event of default under any of the
Partnership's debt agreements and material project contracts or otherwise result
in an adverse change to any material term of such agreements and
contracts.
Credit Agreement
The Partnership has available for its use a credit agreement, as amended
("Credit Agreement"), with a maximum available credit of $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. Under the Credit Agreement, $2.5 million has been posted
to meet letter of credit requirements and $5.0 million is available for working
capital purposes. As of December 31, 2002 and 2001, there were no amounts drawn
or balances outstanding under either the letters of credit or the working
capital arrangement.
The Partnership does not expect the Credit Agreement to be renewed in
August 2003 and is seeking to find a lender to replace the existing Credit
Agreement. If the Partnership is unable to replace the existing Credit
Agreement, it may be required to secure its current letters of credit and any
requests for additional assurances with cash collateral financed with cash flows
from operations. The Partnership believes it will have sufficient cash flows
from operations to secure its letters of credit and to meet its working capital
requirements.
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, 2002, the balance in this Fund was $9.4 million compared
to $4.1 million at December 31, 2001. During the year ending December 31, 2003,
no additional deposits are required to be made into the Fund.
The Interest and Principal Funds relate primarily to the current debt
service on the outstanding Bonds. The applicable Fund Requirements for the
Interest and Principal Funds are the amounts due and payable on the next
semi-annual payment date. On December 26, 2002 and 2001, 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, 2002 and 2001. The June 26, 2003 Interest
Fund Requirement will be $15.5 million and the Principal Fund Requirement will
be $8.5 million.
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, 2002 and 2001, the balance in the Debt Service Reserve Fund was $26.2
million and $24.3 million, respectively. The June 26, 2003 Fund Requirement will
be $28.3 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.
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 2003.
The Partnership has entered into various long-term firm commitments with
approximate dollar obligations as follows (in millions).
2008 and
---------
2003 2004 2005 2006 2007 Thereafter
---- ---- ---- ---- ---- ----------
Fuel Supply and Transportation
Agreements $56.8 $58.1 $57.6 $58.8 $60.0 $359.4
Electric Interconnection and
Transmission Agreements 0.6 0.6 0.6 0.6 0.6 3.7
Long Term Parts Agreement --- --- --- --- 6.9 ---
Site Lease 1.0 1.0 1.0 1.0 1.0 6.7
Water Supply Agreement 1.0 1.0 1.1 1.1 1.2 6.4
Payment in Lieu of Taxes 3.3 3.5 3.7 3.8 3.9 21.0
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.
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 $2.5 million U.S.
dollars and two fuel suppliers, on behalf of the Partnership, have posted
letters of credit totaling $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.
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.
Long Term Parts Agreement - The Partnership has a long-term parts agreement
with GE International, Inc. to purchase a certain dollar amount (the
"Contract Value") of spare parts during the course of the contract. The terms of
the agreement are effective through the end of 2007. As of December 31, 2002,
approximately $6.9 million of the Contract Value remains outstanding and must be
purchased by the end of the agreement.
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.
Water Supply Agreement - 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 quantity of water supply annually. The agreement
is subject to adjustment for changes in market rates beginning in October 2004.
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 GE International, Inc. whereby GE International, Inc.
provides certain operation and maintenance services to both Unit 1 and Unit 2 on
a cost-plus-fixed-fee basis through October 31, 2007.
Market risk is the risk that changes in market conditions will adversely
affect earnings or cashflow. The Partnership categorizes its market risks as
interest rate risk, foreign currency risk, energy commodity price risk and
credit risk. Immediately below are detailed descriptions of the market risks and
explanations as to how each of these risks are managed.
Interest Rate Risk
Interest rate risk is the risk that changes in interest rates could
adversely affect earnings or cashflows. 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. Interest rate risk
sensitivity analysis is used to measure interest rate risk by computing
estimated changes in cashflows as a result of assumed changes in market interest
rates. A 10% decrease in 2002 interest rates would be immaterial to the
Partnership's consolidated financial statements.
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 Risk
Foreign currency risk is the risk of changes in value of pending financial
obligations in foreign currencies in relation to the U.S. dollar. The
Partnership uses currency swap agreements to partially hedge foreign currency
exposure under fuel transportation agreements that are denominated in Canadian
dollars. In the event a counterparty fails to meet the terms of the currency
swap agreements, the Partnership would be exposed to the risk that fluctuating
currency exchange rates may adversely impact its financial results.
The Partnership uses sensitivity analysis to measure its foreign currency
exchange rate exposure not covered by the currency swap agreements. Based upon a
sensitivity analysis at December 31, 2002, a 10 % devaluation of the U.S. Dollar
in relation to the Canadian dollar would be immaterial to the Partnership's
consolidated financial statements.
Energy Commodity Price Risk
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 firm
natural gas supply 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.
Credit risk is the risk of loss the Partnership would incur if
counterparties fail to perform their contractual obligations (these obligations
are reflected as Accounts receivable and Due from affiliates on the consolidated
balance sheets). 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. 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 counterparties it considers to be of investment grade.
As of December 31, 2002, the Partnership's credit risk is primarily
concentrated with the following customers: Con Edison, Niagara Mohawk and the NY
ISO, all of whom are considered to be of investment grade. The parent company of
three of the Partnership's customers, all of whom are related parties, PG&E
Energy Trading - Gas, PG&E Energy Trading - Canada Corporation ("PG&E
Energy Trading - Canada") and PG&E Energy Trading - Power, is considered to
be below investment grade. As of December 31, 2002, the Partnership's net credit
exposure to PG&E Energy Trading - Gas was $160.0 thousand and PG&E
Energy Trading - Canada was $21.0 thousand.
Critical Accounting Policies
The preparation of consolidated financial statements in accordance with
accounting principles generally accepted in the United States involves the use
of estimates and assumptions that affect the recorded amount of assets and
liabilities as of the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Certain of these estimates
and assumptions are considered to be Critical Accounting Policies, due to their
complexity, subjectivity, and uncertainty, along with their relevance to the
financial performance of the Partnership. Actual results may differ
substantially from these estimates. These policies and their key characteristics
are outlined below.
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, SFAS No.
133), on January 1, 2001. SFAS No. 133 requires the Partnership to recognize all
derivatives, as defined in the statement, on the consolidated balance sheets at
fair value. 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. Derivatives are classified as asset for derivative contracts and
liability for derivative contracts on the consolidated balance sheets (see Note
2 to the Consolidated Financial Statements - Accounting for Derivative
Contracts).
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, Accounting for Asset Retirement Obligations. The Partnership
will adopt this statement effective January 1, 2003. SFAS No. 143 provides
accounting requirements for costs associated with legal obligations to retire
tangible, long-lived assets. Under the statement, 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. In each
subsequent period, the liability is accreted to its present value and the
capitalized cost is depreciated over the useful life of the related asset. Upon
adoption, the cumulative effect of applying this statement will be recognized as
a change in accounting principle in the consolidated statements of operations.
The Partnership is currently evaluating the impact of applying this statement.
Based on its current evaluation, the Partnership estimates asset retirement
obligations to be up to approximately $66.0 thousand. The cumulative effect of a
change in accounting principle from unrecognized accretion and depreciation
expense is estimated to be a loss of up to approximately $43.0 thousand.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities, which is effective for exit and
deposal activities initiated after December 31, 2002. In November 2002, the FASB
issued Interpretation No. 45, Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others. This interpretation establishes new disclosure requirements for all
guarantees, but the measurement criteria are applicable to guarantees issued and
modified after December 31, 2002. In January 2003, the FASB Issued
Interpretation No. 46, Consolidation of Variable Interest Entities. This
interpretation applies to variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. For variable interest entities in which an enterprise
holds a variable interest that it acquired before February 1, 2003, application
begins in the first fiscal year or interim period beginning after June 15, 2003.
The Partnership does not expect that implementation of this statement and
interpretations will have a significant impact on its consolidated financial
statements.
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.
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.
The Partnership is exposed to market risk from changes in interest rates,
foreign currency exchange rates, energy commodity prices and credit risk, which
could affect its future results of operations and financial condition. The
Partnership manages its exposure to these risks through its regular operating
and financing activities. (See "Market Risk", included in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations above.)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data required by this item are
presented under Item 15 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
three 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.................. 52 President and Director
Thomas E. Legro.................... 51 Vice President, Controller, Chief
Accounting Officer and Director
Sanford L. Hartman................. 49 Secretary and Director
Managing General Partner:
-------------------------
Name Age Position
---- --- --------
P. Chrisman Iribe.................. 52 President and Director
Thomas E. Legro.................... 51 Vice President, Controller, Chief
Accounting Officer and Director
Sanford L. Hartman................. 49 Secretary and Director
Sanford L. Hartman is Vice President, Chief 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. 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. Mr. Hartman was
elected Secretary of both the Funding Corporation and the Managing General
Partner on October 11, 2002.
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, 2002 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 Partnership 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.
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%
7600 Wisconsin Avenue Partner and (ii) 22.4000%
(Mailing Address: 7500 Old Limited Partner (iii) 18.1440%
Georgetown Road)
Bethesda, Maryland 20814
Partnership Interest PentaGen Investors, L.P. (3)(4) Limited Partner (i) 5.2502%
7600 Wisconsin Avenue (ii) 57.6000%
(Mailing Address: 7500 Old (iii) 46.6560%
Georgetown Road)
Bethesda, Maryland 20814
Partnership Interest RCM Selkirk GP, Inc. (5) General Partner (i) 1.0000%
4400 Post Oak Parkway Ste. 1400 (iii) .2211%
Houston, Texas 77027
Partnership Interest RCM Selkirk LP, Inc. (5) Limited Partner (i) 78.1557%
4400 Post Oak Parkway Ste. 1400 (iii) 17.2789%
Houston, Texas 77027
Partnership interest Aquila Selkirk, Inc.* (6) Limited Partner (i) 13.5523%
20 West Ninth Street. (ii) 20.0000%
Kansas City, Missouri 64105 (iii) 17.7000%
(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).
(4) ArcLight Energy Partners Fund I, L.P., a private equity fund focused on the
electric power sector, is a 50% indirect beneficial owner of Investors.
(5) RCM Selkirk GP is beneficially owned by Robert C. McNair (88.3%) and
members of his family (11.7%). RCM Selkirk LP is beneficially owned by
Robert C. McNair. Mr. McNair has voting control of each of RCM Selkirk GP
and RCM Selkirk LP.
(6) Aquila Merchant Services, Inc. is the indirect beneficial owner of Aquila
Selkirk.
Except as specifically provided or required by law and in certain other
limited circumstances provided in the Partnership Agreement, Limited Partners
may not participate in the management or control of the Partnership. The
Managing General Partner is an affiliate of Investors, which is a Limited
Partner, and JMCS I Management, the Project Management Firm. RCM Selkirk GP and
RCM Selkirk LP are also affiliated.
All of the issued and outstanding capital stock of the Funding Corporation
is owned by the Partnership.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
JMCS I Management, an indirect, wholly owned subsidiary of NEG, provides
management and administrative services for the Partnership under the
Administrative Services Agreement. All of the directors 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.
ITEM 14. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Based on an evaluation of the Partnership's disclosure controls and
procedures conducted on February 6, 2003, the principal executive officers and
principal financial officers of JMC Selkirk, Inc., as Managing General Partner
of Selkirk Cogen Partners, L.P., and Selkirk Cogen Funding Corporation have
concluded that such controls and procedures effectively ensure that information
required to be disclosed by the Partnership in reports the Partnership files or
submits under the Securities and Exchange Act of 1934 is recorded, processed,
summarized, and reported, within the time periods specified in the SEC's rules
and forms.
There were no significant changes in internal controls or in other factors
that could significantly affect these controls subsequent to the date of their
evaluation.
(a) 1. Financial Statements
The following financial statements are filed as part of this Report:
Independent Auditors' Report for the years ended December 31, 2002,
2001 and 2000....................................................... F-1
Consolidated Balance Sheets as of December 31, 2002 and 2001......... F-2
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001 and 2000.................................... F-3
Consolidated Statements of Changes in Partners' Deficits for the
years ended December 31, 2002, 2001 and 2000........................ F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000.................................... 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.
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, 2002 and 2001,
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, 2002. 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 consolidated financial statements present fairly, in all
material respects, the financial position of the Partnership as of December 31,
2002 and 2001, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2002, in conformity with
accounting principles generally accepted in the United States of America.
See Note 1 to the consolidated financial statements for discussion of the
financial difficulties of PG&E National Energy Group, Inc. and certain
affiliates.
As discussed in Note 2 to the consolidated financial statements, during 2001 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”, and certain
interpretations issued by the Derivatives Implementation Group. Also as
discussed in Note 2 to the consolidated financial statements, in 2000 the
Partnership changed its method of accounting for major maintenance and overhaul
costs.
/s/ DELOITTE & TOUCHE LLP
McLean, Virginia
February 24, 2003
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(In Thousands)
- -------------------------------------------------------------------------------------------------------------------------
2002 2001
------------------ ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,716 $ 4,546
Restricted funds 4,399 7,699
Accounts receivable, net of allowance of $0 and $32
in 2002 and 2001, respectively 20,116 17,789
Due from affiliates 1,757 1,127
Fuel inventory and supplies 6,436 10,228
Other current assets 616 511
Asset for derivative contracts --- 446
------------------ ----------------
Total current assets 36,040 42,346
------------------ ----------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 374,906 373,476
Less: Accumulated depreciation 111,903 99,563
------------------ ----------------
Plant and equipment, net 263,003 273,913
------------------ ----------------
LONG-TERM RESTRICTED FUNDS 34,600 24,314
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $9,979 and $8,901 in 2002 and 2001, respectively 6,312 7,390
------------------ ----------------
TOTAL ASSETS $ 339,955 $ 347,963
================== ================
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 71 $ 1,729
Accrued fuel expenses 10,953 8,689
Accrued property taxes 3,300 2,296
Accrued operating and maintenance expenses 1,539 1,262
Other accrued expenses 3,043 4,530
Due to affiliates 1,821 2,008
Current portion of long-term bonds 17,365 13,529
Current portion of liability for derivative contracts 2,586 3,688
------------------ ----------------
Total current liabilities 40,678 37,731
LONG-TERM LIABILITIES:
Deferred revenue 3,890 4,597
Other long-term liabilities 6,691 7,070
Long-term bonds - net of current portion 331,870 349,235
Liability for derivative contracts - net of current portion 2,539 5,113
------------------ ----------------
Total liabilities 385,668 403,746
------------------ ----------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (403) (458)
Limited partners' deficits (40,185) (46,524)
Accumulated other comprehensive loss (5,125) (8,801)
------------------ ----------------
Total partners' deficits (45,713) (55,783)
------------------ ----------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 339,955 $ 347,963
================== ================
The accompanying notes are an integral part of these consolidated financial statements.
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
--------------- --------------- ----------------
OPERATING REVENUES:
Electric and steam revenues $ 205,720 $ 210,504 $ 205,539
Fuel revenues 21,858 19,221 28,838
-------------- -------------- ----------------
Total operating revenues 227,578 229,725 234,377
--------------- --------------- ----------------
COST OF REVENUES:
Fuel and transmission costs 116,250 125,055 134,272
Unrealized (gain) / loss on derivative 446 (965) ---
contracts
Other operating and maintenance 24,120 18,065 16,666
Depreciation 12,543 12,483 12,468
--------------- --------------- ----------------
Total cost of revenues 153,359 154,638 163,406
--------------- --------------- ----------------
GROSS PROFIT 74,219 75,087 70,971
--------------- --------------- ----------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 1,508 1,898 2,244
Other general and administrative 2,744 2,394 2,152
--------------- --------------- ----------------
Total other operating expenses 4,252 4,292 4,396
--------------- --------------- ----------------
OPERATING INCOME 69,967 70,795 66,575
--------------- --------------- ----------------
INTEREST (INCOME) EXPENSE:
Interest income (890) (2,015) (3,176)
Interest expense 32,907 33,926 35,203
--------------- --------------- ----------------
Total interest expense, net 32,017 31,911 32,027
--------------- --------------- ----------------
INCOME BEFORE CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE 37,950 38,884 34,548
CUMULATIVE EFFECT OF A CHANGE IN --- (519) 7,866
ACCOUNTING PRINCIPLE --------------- --------------- ----------------
NET INCOME $ 37,950 $ 38,365 $ 42,414
=============== =============== ================
NET INCOME ALLOCATION:
General partners $ 380 $ 385 $ 425
Limited partners 37,570 37,980 41,989
--------------- --------------- ----------------
TOTAL $ 37,950 $ 38,365 $ 42,414
=============== =============== ================
The accompanying notes are an integral part of these consolidated financial statements.
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' DEFICITS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(In Thousands)
- ---------------------------------------------------------------------------------------------------------------------------
Accumulated
Other Total
General Limited Comprehensive Partners'
Partners Partners Income (Loss) Deficits
---------------- -------------- ---------------- ---------------
BALANCE, JANUARY 1, 2000 $ (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 income (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)
Net income 380 37,570 --- 37,950
Other comprehensive income (loss) --- --- 3,676 3,676
---------------- -------------- ---------------- ---------------
Comprehensive Income 380 37,570 3,676 41,626
---------------- -------------- ---------------- ---------------
Capital distributions (325) (31,231) --- (31,556)
---------------- -------------- ---------------- ---------------
BALANCE, DECEMBER 31, 2002 $ (403) $ (40,185) $ (5,125) $ (45,713)
================ ============== ================ ===============
The accompanying notes are an integral part of these consolidated financial statements.
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(In Thousands)
2002 2001 2000
-------------- -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 37,950 $ 38,365 $ 42,414
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 13,621 13,595 13,596
Loss on disposal of equipment 504 92 17
Unrealized (gain) / loss on derivative contracts 446 (965) ---
Deferred revenue (707) (707) (677)
Increase (decrease) in cash resulting from a change in:
Restricted funds (5,071) (856) 6,205
Accounts receivable (2,327) 2,308 (4,592)
Due from affiliates (630) 2,755 (3,455)
Fuel inventory and supplies 3,792 (3,535) 138
Other current assets (105) (75) (241)
Accounts payable (1,658) 1,680 (2,077)
Accrued fuel expenses 2,264 (6,479) 7,070
Accrued property taxes 1,004 (954) 550
Accrued operating and maintenance expenses 277 (111) 470
Other accrued expenses (1,487) 2,797 320
Due to affiliates (187) 1,373 166
Other long-term liabilities (379) (180) 20
-------------- -------------- --------------
Net cash provided by operating activities 47,307 49,622 52,058
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (2,137) (1,174) (775)
Proceeds from disposal of plant and equipment --- 10 ---
-------------- -------------- --------------
Net cash used in investing activities (2,137) (1,164) (775)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds (1,915) (336) (1,293)
Distributions to partners (31,556) (35,701) (41,228)
Repayment of long-term debt (13,529) (11,062) (7,307)
-------------- -------------- --------------
Net cash used in financing activities (47,000) (47,099) (49,828)
-------------- -------------- --------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (1,830) 1,359 1,455
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 4,546 3,187 1,732
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS, $ 2,716 $ 4,546 $ 3,187
END OF YEAR ============== ============== ==============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 31,842 $ 32,825 $ 34,082
============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
- -----------------------------------------------------------------------------------------------------
1. ORGANIZATION AND OPERATION
Selkirk Cogen Partners, L.P. was organized on December 15, 1989 as a Delaware
limited partnership. 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 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”). 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”), Aquila Selkirk, Inc.
(“Aquila Selkirk”, formerly EI Selkirk, Inc.) and RCM Selkirk, LP,
Inc. (“RCM Selkirk LP”).
The Managing General Partner is responsible for managing and controlling the
business and affairs of the Partnership, subject to certain powers which are
vested in the management committee of the Partnership (the “Management
Committee”) under the Partnership Agreement. Each General Partner has a
voting representative on the Management Committee, which, subject to certain
limited exceptions, acts by unanimity. Thus, the General Partners, and
principally the Managing General Partner, exercise control over the Partnership.
JMCS I Management, Inc. (“JMCS I Management”), an affiliate of the
Managing General Partner, is acting as the project management firm (the
“Project Management Firm”) for the Partnership, and as such is
responsible for the implementation and administration of the Partnership’s
business under the direction of the Managing General Partner. Upon the
occurrence of certain events specified in the Partnership Agreement, RCM Selkirk
GP may assume the powers and responsibilities of the Managing General Partner
and of the Project Management Firm. Under the Partnership Agreement, each
General Partner other than the Managing General Partner may convert its general
partnership interest to that of a Limited Partner.
JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating Company
(“Beale”), 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, the parent company of Pacific Gas and Electric Company (the
“Utility”).
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
principally 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.
Relationship with PG&E Corporation and NEG - In December 2000, and
January and February 2001, PG&E Corporation and NEG completed a corporate
restructuring of NEG that 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.
On April 6, 2001, the Utility filed a voluntary petition for relief under the
provisions of Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy
Code”) in the United States Bankruptcy Court for the Northern District of
California (“Bankruptcy Court”). Pursuant to the 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. The Utility and PG&E Corporation jointly filed a plan of
reorganization with the Bankruptcy Court that entails separating the Utility
into four distinct businesses. The proposed plan of reorganization does not
directly affect NEG or any of its subsidiaries. The Managing General Partner
believes that NEG and its direct and indirect subsidiaries, including JMC
Selkirk, Investors, and the Partnership, would not be substantively consolidated
with PG&E Corporation in any insolvency or bankruptcy proceeding involving
PG&E Corporation or the Utility.
As a result of the sustained downturn in the power industry, NEG and certain of
its affiliates have experienced a financial downturn, which caused the major
credit rating agencies to downgrade NEG and certain of its affiliates’
credit ratings to below investment grade. The credit rating agency action has
had no material impact on the financial condition or results of operations of
the Partnership.
On October 8, 2002, Moody’s Investor Services (“Moody’s”)
stated that in conjunction with the downgrade of NEG it had placed the
Partnership’s debt under review for possible downgrade. On October 15,
2002, Standard and Poor’s (“S&P”) stated that the recent
downgrade of NEG will not have an affect on the rating of the Partnership’s
debt at this time. S&P’s rating of the Partnership’s debt is
“BBB-". On November 5, 2002, Moody’s issued an opinion update
changing the rating outlook of the Partnership’s debt to “under review
for possible downgrade” from “stable” for the Partnership’s
debt due in 2007 and “negative outlook” for the Partnership’s
debt due in 2012. Moody’s rating of the Partnership’s debt is
“Baa3". A downgrade of the credit ratings of the Partnership’s
debt due in 2007 or 2012 by S&P or Moody’s (or both) would not be an
event of default under any of the Partnership’s debt agreements and
material project contracts or otherwise result in an adverse change to any
material term of such agreements and contracts.
If the lenders exercise their default remedies or if the financial commitments
are not restructured, NEG and the affected affiliates may be compelled to seek
protection under or be forced into a proceeding under the U.S. Bankruptcy Code.
NEG owns an indirect interest in the Partnership, and through its indirect,
wholly owned subsidiaries, JMC Selkirk and JMCS I Management, manages the
Partnership. The Partnership cannot be certain that an insolvency or bankruptcy
involving NEG or any of its subsidiaries would not affect NEG’s ownership
arrangements with respect to the Partnership or the ability of JMC Selkirk or
JMCS I Management to manage the Partnership. The Partnership Agreement provides
certain management rights to RCM Selkirk GP in the event that JMC Selkirk were
to be included in a bankruptcy involving NEG, including (i) the removal of JMC
Selkirk as the managing general partner, (ii) the appointment of itself as the
successor managing general partner, and (iii) the termination of the
administrative services agreement with JMCS I Management and subsequent
appointment of a RCM Selkirk GP affiliate as the project management firm.
Enforcement of these rights by RCM Selkirk GP could, however, be delayed or
impeded as a result of any bankruptcy proceeding involving JMC Selkirk.
Moreover, the bankruptcy of any partner of the Partnership would be an event of
default under the Partnership’s Credit Agreement. Currently, the
Partnership has contingent reimbursement obligations arising under letters of
credit issued under this Credit Agreement in the amount of approximately $2.5
million, which the Partnership believes could be secured with cash collateral
financed with cash flows from operations (Note 5).
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.
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, SFAS No. 133), on January 1, 2001. SFAS No. 133 requires
the Partnership to recognize all derivatives, as defined in the statement, on
the consolidated balance sheets at fair value. 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. Derivatives are classified as asset for
derivative contracts and liability for derivative contracts on the consolidated
balance sheets.
DIG Issue C15 changed the definition of normal purchases and sales for certain
power contracts. The Partnership determined that all of its power contracts
continue to qualify for the normal purchases and sales exemption. DIG Issue C16
disallowed normal purchases and sales treatment for commodity contracts (other
than power contracts) that contain volumetric variability or optionality. The
Partnership determined that one of its long-term fuel contracts failed to
continue qualifying for the normal purchase exemption under the requirements of
DIG Issue C16. However, because the long-term fuel contract has market
based pricing, the Partnership currently estimates its fair value to always be
zero, resulting in no impact to the Partnership’s consolidated financial
statements.
DIG Issue C10 disallowed normal purchases and sales treatment for commodity
contracts (other than power contracts) that contain volumetric variability or
optionality. The Partnership determined that certain of its gas contracts no
longer qualify for normal purchases and sales treatment under this
interpretation. Beginning July 1, 2001, these contracts were required to be
recorded on the balance sheet at fair value and marked-to-market through
earnings. The cumulative effect of this change in accounting principle was the
recording of a loss totaling approximately $519,000 on July 1, 2001. Changes in
the fair value of these contracts are recorded on the consolidated statements of
operations as an unrealized gain or loss on derivative contracts (Note 3).
The transition adjustment to implement SFAS No. 133 on January 1, 2001, 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. The
Partnership has two foreign currency exchange contracts to hedge against
fluctuations of fuel transportation costs, which are 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).
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, 2002 and 2001, fuel inventory and
supplies consisted mainly of spare parts.
Plant and Equipment - Plant and equipment is stated at cost, net of
accumulated depreciation. Depreciation is computed on a straight-line basis over
the estimated useful lives of the related assets. Capitalized modifications to
leased properties are amortized using the straight-line method over the shorter
of the lease term, through September 2014, or the asset’s estimated useful
life. Other assets are depreciated as follows:
Cogeneration 30 years
Computer Systems 3 to 7
Office Equipment 5
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.
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. All revenues are
recorded in accordance with the Securities and Exchange Commission Staff
Accounting Bulletin (“SAB”) No. 101, Revenue Recognition, as
amended.
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.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No. 121,
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
statement 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 statement is effective for fiscal years
beginning after December 15, 2001. This statement was adopted on January 1,
2002, and did not have an impact on the Partnership’s consolidated
financial statements.
Accounting Principles Issued But Not Yet Adopted - In June 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations. The
Partnership will adopt this statement effective January 1, 2003. SFAS
No. 143 provides accounting requirements for costs associated with legal
obligations to retire tangible, long-lived assets. Under the statement, 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.
In each subsequent period, the liability is accreted to its present value and
the capitalized cost is depreciated over the useful life of the related asset.
Upon adoption, the cumulative effect of applying this statement will be
recognized as a change in accounting principle in the consolidated statements of
operations. The Partnership is currently evaluating the impact of applying this
statement. Based on its current evaluation, the Partnership estimates asset
retirement obligations to be approximately $66,000. The cumulative effect of a
change in accounting principle from unrecognized accretion and depreciation
expense is estimated to be a loss of approximately $43,000.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which is effective for exit and disposal
activities initiated after December 31, 2002. In November 2002, the FASB issued
Interpretation No. 45, Guarantor’s Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others. This interpretation establishes new disclosure requirements for all
guarantees, but the measurement criteria are applicable to guarantees issued and
modified after December 31, 2002. In January 2003, the FASB issued
Interpretation No. 46, Consolidation of Variable Interest Entities. This
interpretation applies to variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. For variable interest entities in which an enterprise
holds a variable interest that it acquired before February 1, 2003, application
begins in the first fiscal year or interim period beginning after June 15, 2003.
The Partnership does not expect that implementation of this statement and
interpretations will have a significant impact on its consolidated financial
statements.
Reclassifications - Certain reclassifications have been made in the 2001
and 2000 consolidated financial statements to conform to the current-year
presentation. Amortization of deferred financing charges has previously been
included in other operating expenses, and has been reclassified into interest
expense. The net effect of the reclassification on interest expense is an
increase of approximately $1,078,000 in 2002, $1,112,000 in 2001 and $1,128,000
in 2000. All prior periods presented have been reclassified to conform to the
current presentation.
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, which had a term of ten years and expired on December 25, 2002, the
Partnership exchanges approximately $368,000 U.S. dollars for $458,000 Canadian
dollars on a monthly basis. 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 with the offset
in other comprehensive income (loss) (Note 2).
The amount charged to fuel costs as a result of losses realized from these
contracts for the year ended December 31, 2002 totaled approximately $3,226,000,
compared to approximately $3,245,000 in 2001 and approximately $2,463,000 in
2000. The Partnership expects that net derivative losses of approximately
$2,586,000, included in accumulated other comprehensive loss as of December 31,
2002, 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 years ended December 31,
2002 and 2001 (in thousands):
For the years ended
December 31, 2002 December 31, 2001
--------------------- -------------------
Beginning accumulated other comprehensive loss at
January 1 $ (8,801) $ (8,968)
Net change of current period hedging transactions
gain (loss) 450 (3,078)
Net reclassification to earnings 3,226 3,245
--------------------- -------------------
Ending accumulated other comprehensive loss at
December 31 $ (5,125) $ (8,801)
===================== ===================
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. (1) Aquila East Coast Generation, Inc.(2) 13.55 20.00
RCM Selkirk LP, Inc. RCM Holdings, Inc. 78.16 -
(1) Formerly El Selkirk, Inc.
(2) 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%.
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):
2003 17,365
2004 19,587
2005 25,230
2006 31,657
2007 39,441
2008 and thereafter 215,955
---------
$ 349,235
=========
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. The balance in the Major Maintenance Reserve Fund was approximately
$9,355,000 at December 31, 2002, compared to approximately $4,091,000 at
December 31, 2001.
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, 2002 and 2001, 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, 2002 and 2001.
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. The balance in the
Debt Service Reserve Fund was approximately $26,229,000 at December 31, 2002,
compared to approximately $24,314,000 at December 31, 2001.
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. Under the Credit
Agreement, $2.5 million has been posted to meet letter of credit requirements
and $5.0 million is available for working capital purposes. As of December 31,
2002 and 2001, there were no amounts drawn or balances outstanding under either
the letters of credit or the working capital arrangement.
6. FAIR VALUE 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) was approximately $324,964,000 at December 31,
2002, compared to approximately $371,402,000 at December 31, 2001.
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 $5,125,000 at
December 31, 2002, compared to approximately $8,801,000 at December 31, 2001.
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 (accounts
receivable and due from affiliates). 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. 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 counterparties it considers to be of
investment grade (Note 1).
As of December 31, 2002, the Partnership’s credit risk is primarily
concentrated with the following customers: Consolidated Edison Company of New
York, Inc., Niagara Mohawk Power Corporation and the New York Independent System
Operator, all of whom are considered to be of investment grade. The parent
company of three of the Partnership’s customers, all of whom are related
parties, PG&E Energy Trading – Gas Corporation (“PG&E Energy
Trading – Gas”), PG&E Energy Trading - Canada Corporation
(“PG&E Energy Trading – Canada”) and PG&E Energy Trading
- - Power, L.P. (“PG&E Energy Trading – Power”), is considered
to be below investment grade. As of December 31, 2002, the Partnership’s
net credit exposure to PG&E Energy Trading – Gas was approximately
$160,000 and PG&E Energy Trading – Canada was approximately $21,000.
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 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 Independent System Operator, 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.
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.
2008 and
--------
2003 2004 2005 2006 2007 Thereafter
---- ---- ---- ---- ---- ----------
Fuel Supply and Transportation
Agreements $56,800 $58,100 $57,600 $58,800 $60,000 $359,400
Electric Interconnection and
Transmission Agreements 600 600 600 600 600 3,650
Long Term Parts Agreement --- --- --- --- 6,885 ---
Site Lease 1,000 1,000 1,000 1,000 1,000 6,667
Water Supply Agreement 1,014 1,014 1,065 1,118 1,174 6,436
Payment in Lieu of Taxes 3,300 3,500 3,700 3,800 3,900 21,000
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.
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.
Water Supply Agreement - 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 quantity of water supply annually. The agreement
is subject to adjustment for changes in market rates beginning in October 2004.
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 GE International, Inc. whereby GE International, Inc.
provides certain operation and maintenance services to both Unit 1 and Unit 2 on
a cost-plus-fixed-fee basis through October 31, 2007.
Other Contingencies - The Partnership is a party in various legal
proceedings and potential claims arising in the ordinary course of its business.
Management does not believe that the resolution of these matters will have a
material adverse effect on the Partnership’s consolidated financial
position or results of operations.
On November 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,
the Partnership cannot assess whether a settlement can be achieved, the likely
outcome of the adjudicatory hearing if no settlement is achieved, or 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. The cost of services
provided by JMCS I Management are included in administrative services –
affiliates in the accompanying consolidated statements of operations. The total
amount due to JMCS I Management for these services at December 31, 2002, was
approximately $249,000.
Gas purchased from affiliates is as follows (dollars in thousands):
For the years ended
December 31, December 31, December 31,
2002 2001 2000
---------------- --------------- ----------------
PG&E Energy Trading - Gas $ 11,456 $ 4,898 $ 379
Pittsfield Generating 4 119 156
MASSPOWER 42 2,556 358
Gas sold to affiliates is as follows (dollars in thousands):
For the years ended
December 31, December 31, December 31,
2002 2001 2000
---------------- --------------- -----------------
PG&E Energy Trading - Gas $ 21,126 $ 16,685 $ 218
PG&E Energy Trading - Canada 280 --- 22
Pittsfield Generating 1 80 3,567
MASSPOWER 59 17 ---
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. Firm fuel transportation services for
the year ended December 31, 2002 totaled approximately $7,456,000, compared to
approximately $7,741,000 in 2001 and approximately $8,227,000 in 2000. These
services are recorded as fuel costs in the accompanying consolidated statements
of operations. The total amount due to IGTS for firm transportation at December
31, 2002, was approximately $633,000.
F-19
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) 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")
3.4 Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of
November 1, 1994 (incorporated by reference to the Registrant's Form 10-Q for the quarter ended June 30, 1995
(File No. 33-83618), Exhibit 3.1)
3.5 Amendment No. 2 to the Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of
June 16, 1995 (incorporated by reference to the Registrant's Form 10-Q for the quarter ended June 30, 1995 (File
No. 33-83618), Exhibit 3.2)
3.6 Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of
November 15, 2001 (incorporated herein by reference to the Registrant's Form 10-K for the year ended December 31,
2001 (File No. 33-83618), Exhibit 3.7)
4.1(1) Trust Indenture, dated as of May 1, 1994, among the Funding Corporation, the Partnership and Bankers Trust Company, as
trustee (the "Trustee")
4.2(1) First Series Supplemental Indenture, dated as of May 1, 1994, among the Funding Corporation, the Partnership and the
Trustee
4.3(1) Registration Agreement, dated April 29, 1994, among the Funding Corporation, the Partnership, CS First Boston
Corporation, Chase Securities, Inc. and Morgan Stanley & Co. Incorporated
4.4(1) Partnership Guarantee, dated as of May 1, 1994, of the Partnership to the Trustee (2007)
4.5(1) Partnership Guarantee, dated as of May 1, 1994, of the Partnership to the Trustee (2012)
10.1 Credit Facilities
10.1.1(1) Credit Bank Working Capital and Reimbursement Agreement, dated as of May 1, 1994, among the Partnership, The Chase
Manhattan Bank, N.A. ("Chase"), as Agent, and the other Credit Banks identified therein
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 Amendment No. 2 to Credit Agreement, dated April 7, 1995, between the Partnership and Dresdner Bank AG, New York Branch
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 1997 (File No.
33-83618), Exhibit 10.1)
10.1.4 Amendment No. 3 to Credit Agreement, dated July 1, 1997, between the Partnership and Dresdner Bank AG, New York Branch
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 1997 (File No.
33-83618), Exhibit 10.1)
10.1.5 Amendment No. 4 to Credit Agreement, dated November 16, 1998, between the Partnership and Dresdner Bank AG, New York Branch
(incorporated by reference to the Registrant’s Form 10-K for the year ended December 31, 1998 (File No.
33-83618), Exhibit 10.1.5)
10.1.6 Amendment No. 5 to Credit Agreement, dated August 1, 2000, between the Partnership and Dresdner Bank AG, New York Branch
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 2000 (File No.
33-83618), Exhibit 10.1)
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 Amended and Restated Power Purchase Agreement dated as of July 1, 1998 between the Partnership and Niagara Mohawk
(incorporated by reference to the Registrant’s Form 8-K filed September 16, 1998 (File No. 33-83618), Exhibit
10.1)
10.2.2 Mutual General Release and Agreement dated as of July 1, 1998 between the Partnership and Niagara Mohawk
(incorporated by reference to the Registrant’s Form 8-K filed September 16, 1998 (File No. 33-83618), Exhibit
10.1)
10.2.3 Letter Agreement dated as of October 9, 2000, between the Partnership and Niagara Mohawk (incorporated by reference
to the Registrant’s Form 10-K for the year ended December 31, 2000 (File No. 33-83618), Exhibit 10.2.8)
10.2.4(1) Agreement dated as of March 31, 1994, between the Partnership and Niagara Mohawk
10.2.5(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
10.2.6(1) License Agreement between the Partnership and Niagara Mohawk, dated as of October 23, 1992
10.2.7(1) Power Purchase Agreement, dated as of April 14, 1989, between Con Edison Company of New York, Inc. ("Con Edison") and
JMC Selkirk
10.2.8(1) Rider to Power Purchase Agreement, dated as of September 13, 1989, between Con Edison and JMC Selkirk
10.2.9(1) First Amendment to Power Purchase Agreement, dated as of September 13, 1991, between Con Edison and JMC Selkirk
10.2.10(1) Letter Agreement Regarding Extending the Term of the Power Purchase Agreement, dated as of May 28, 1992, between Con
Edison and JMC Selkirk
10.2.11(1) Second Amendment to Power Purchase Agreement, dated as of October 22, 1992, between Con Edison and JMC Selkirk
10.2.12 Third Amendment to Power Purchase Agreement, dated as of September 13, 1996, between Con Edison and the Partnership
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended September 30, 1996 (File No.
33-83618), Exhibit 10.1)
10.2.13(1) Letter Agreement Regarding Arbitration, dated October 22, 1992, between Con Edison and JMC Selkirk
10.2.14(1) Letter Agreement Regarding Sale of Capacity above 265 MW, dated as of October 22, 1992, between Con Edison and JMC
Selkirk
10.2.15(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
10.2.16(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 Third Amendment to Steam Sales Agreement, dated May 31, 1995, between the Partnership and General Electric
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 (File No.
33-83618), Exhibit 10.1)
10.4.5 Second Amended and Restated O&M Agreement dated July 18, 2000, between the Partnership and GE International Inc.
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 2000 (File No. 33-83618),
Exhibit 10.4)
10.5 Fuel Supply Contracts
10.5.1 Second Amended and Restated Gas Purchase Contract, dated as of May 6, 1998, between the Partnership and Paramount
(incorporated by reference to the Registrant’s Form 8-K filed September 16, 1998 (File No.
33-83618), Exhibit 10.3)
10.5.2 First Amending Agreement dated as of the November 1, 2002, to the Second Amended and Restated Gas Purchase Contract
between the Partnership and Paramount (incorporated by reference to the Registrant’s Form 10-Q for the quarter
ended September 30, 2002 (File No. 33-83618), Exhibit 10.5.16)
10.5.3(1) Letter Agreement, dated as of October 25, 1993, between the Partnership and Paramount
10.5.4(1) Indemnity Agreement, dated as of February 20, 1989, by the Partnership in favor of Paramount
10.5.5(1) Letter Agreement, dated as of June 11, 1990, between the Partnership and Paramount
10.5.6(1) Indemnity Amending and Supplemental Agreement, dated as of June 19, 1990, between the Partnership and Paramount
10.5.7(1) Intercreditor Agreement, dated as of October 21, 1992, between Paramount, the Partnership and Chase, as Agent
10.5.8(1) Specific Assignment of Unit 1 TransCanada Transportation Contract, dated as of December 20, 1991, by the Partnership
to Paramount
10.5.9(1) Amendment No. 1 to Specific Assignment, dated as of October 21, 1992, between the Partnership and Paramount
10.5.10(1) Amended and Restated Gas Purchase Agreement, dated as of January 21, 1993, between the Partnership and Atcor Ltd.
("Atcor")
10.5.11(1) Amended and Restated Gas Purchase Agreement, dated as of October 22, 1992, between the Partnership, as assignee, and
Imperial Oil Resources ("Imperial")
10.5.12(1) Amended and Restated Gas Purchase Agreement, dated as of October 22, 1992, between the Partnership, as assignee, and
PanCanadian Pertroleum Limited ("PanCanadian")
10.5.13(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 Amending Agreement, dated as of July 20, 1998, between the Partnership and TransCanada (incorporated by reference to
the Registrant’s Form 8-K filed September 16, 1998 (File No. 33-83618), Exhibit 10.4)
10.6.6(1) Firm Natural Gas Transportation Agreement, dated as of April 18, 1991, between Tennessee Gas Pipeline and the
Partnership
10.6.7(1) Clarification Letter from Tennessee, dated April 18, 1991, between the Partnership and Tennessee
10.6.8(1) Supplemental Agreement (Unit 1), dated April 18, 1991, between the Partnership and Tennessee
10.6.9(1) Operational Balancing Agreement, dated as of September 1, 1993, between the Partnership and Tennessee
10.6.10(1) Interruptible Transportation Agreement, dated as of September 1, 1993, between the Partnership and Tennessee
10.6.11(1) License Agreement for the Ten-Speed 2 System, dated as of July 21, 1993, between the Partnership, Tennessee,
Midwestern Gas Transmission Company and East Tennessee Natural Gas Company
10.6.12 Firm Transportation Negotiated Rate Letter Agreement, dated as of June 18, 2002, between the Partnership and Tennessee
(incorporated by reference to the Registrant’s Form 10-Q for the quarter ended June 30, 2002 (File No.
33-83618), Exhibit 10.6.20)
10.6.13 Agreement under FT-A Rate Schedule, dated as of June 19, 2002, between the Partnership and Tennessee (incorporated by
reference to the Registrant’s Form 10-Q for the quarter ended June 30, 2002 (File No. 33-83618), Exhibit
10.6.21)
10.6.14 Gas Transportation Agreement, dated as of August 1, 2002, between the Partnership and Tennessee (incorporated by
reference to the Registrant’s Form 10-Q for the quarter ended June 30, 2002 (File No. 33-83618), Exhibit
10.6.22)
10.6.15(1) Firm Service Contract for Firm Transportation Service, dated as of March 16, 1994, between the Partnership and
TransCanada
10.6.16(1) Letter Agreement, dated as of March 24, 1994, between the Partnership and TransCanada
10.6.17(1) Gas Transportation Contract for Firm Reserved Service, dated as of April 5, 1994, between the Partnership and Iroquois
10.6.18(1) Letter Agreement, dated as of March 31, 1994, between the Partnership and Iroquois
10.6.19(1) Firm Natural Gas Transportation Agreement, dated as of April 11, 1994, between the Partnership and Tennessee
10.6.20(1) Tennessee Supplemental Agreement (Unit 2), dated as of October 21, 1992, between Tennessee and the Partnership
10.6.21(1) Letter Agreement, dated September 22, 1993, between the Partnership and Tennessee
10.6.22 Consent and Agreement, dated May 15, 1995, between the Partnership, Iroquois and the Trustee (incorporated by reference
to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 (File No. 33-83618), Exhibit 10.2)
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 Letter Agreement dated as of April 18, 1997, between the Partnership and Niagara Mohawk (incorporated by reference to
the Registrant’s Form 10-Q for the quarter ended March 31, 1997 (File No. 33-83618), Exhibit 10.1)
10.7.4(1) Interconnection Agreement (Unit 1), dated as of October 20, 1992, between Niagara Mohawk and SCP II
10.7.5(1) Interconnection Agreement (Unit 2), dated as of October 20, 1992, between Niagara Mohawk and SCP II
10.8 Administrative Services Agreements and Water Supply Agreement
10.8.1(1) Project Administrative Services Agreement, dated as of June 15, 1992, between JMCS I Management, Inc. ("JMCS I
Management") and the Partnership
10.8.2(1) First Amendment to Project Administrative Services Agreement, dated as of October 23, 1992, between JMCS I Management
and the Partnership
10.8.3(1) Second Amendment to Project Administrative Services Agreement, dated as of May 1, 1994, between JMCS I Management and
the Partnership
10.8.4(1) Water Supply Agreement, dated as of May 6, 1992, between the Town of Bethlehem, New York and the Partnership
10.9 Real Estate Documents
10.9.1(1) Second Amended and Restated Lease Agreement, dated as of October 21, 1992, between the Partnership and General Electric
10.9.2(1) Amended and Restated First Amendment to Second Amended and Restated Lease Agreement, dated as of April 30, 1994,
between the Partnership and General Electric
10.9.3(1) Unit 2 Grant of Easement, dated as of October 21, 1992, made by General Electric in favor of the Partnership
(regarding Unit 2 Substation and Transmission Line)
10.9.4(1) Declaration of Restrictive Covenants by General Electric, dated as of October 21, 1992 (regarding Wetlands Remediation
Areas)
10.9.5(1) Utilities Building Lease Agreement, dated as of October 21, 1992, between General Electric, as Landlord, and the
Partnership, as Tenant
10.9.6(1) Easement Agreement, dated as of May 27, 1992, between Charles Waldenmaier and the Partnership, as assignee
10.9.7(1) Facility Lease Agreement, dated as of October 21, 1992, between the Partnership, as Landlord, and the Town of
Bethlehem, New York Industrial Development Agency ("IDA"), as Tenant
10.9.8(1) Amended and Restated First Amendment to Facility Lease Agreement, dated as of April 30, 1994, between the Partnership
and the IDA
10.9.9(1) Sublease Agreement, dated as of October 21, 1992, between the Partnership, as Subtenant, and the IDA, as Sublandlord
10.9.10(1) Amended and Restated First Amendment to Sublease Agreement, dated as of April 30, 1994, between the Partnership and
the IDA
10.9.11(1) Payment in Lieu of Taxes Agreement, dated as of October 21, 1992, between the Partnership and the IDA
10.10 Security Documents
10.10.1(1) Assignment of Agreements, dated as of May 1, 1994, among Yasuda Bank and Trust Company (U.S.A.) ("Yasuda"), Dresdner
Bank AG, New York and Grand Cayman Branches ("Dresdner"), the Depositary Agent, the Collateral Agent, the
Partnership and the Funding Corporation
10.10.2(1) Depositary Agreement, dated as of May 1, 1994, among the Funding Corporation, the Partnership, Bankers Trust Company
as collateral agent ("Collateral Agent") and Bankers Trust Company, as depositary agent (the "Depositary Agent")
10.10.3(1) Equity Contribution Agreement, dated as of May 1, 1994, among the Partnership, Cogen LP, Cogen GP, Makowski Selkirk
and Chase
10.10.4(1) Cash Collateral Agreement, dated as of May 1, 1994, among Makowski Selkirk, the Partnership and Chase, as Agent
10.10.5(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen LP, the Partnership and Chase, as Agent
10.10.6(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen GP, the Partnership and Chase, as Agent
10.10.7(1) Agreement of Spreader, Consolidation and Modification of Leasehold Mortgages, Security Agreements and Fixture
Financing Statements, (the "First Consolidated Mortgage"), dated as of May 1, 1994, in the principal amount of
$227,000,000 among the Partnership, the IDA and the Collateral Agent
10.10.8(1) Agreement of Spreader, Consolidation and Modification of Leasehold Mortgages, Security Agreements and Fixture
Financing Statements, dated as of May 1, 1994, in the principal amount of $122,000,000 among the Partnership, the
IDA and the Collateral Agent
10.10.9(1) Agreement of Spreader and Modification of Leasehold Mortgage (the "Restated Mortgage"), dated as of May 1, 1994, in
the principal amount of $43,000,000 among the Partnership, the IDA and the Collateral Agent
10.10.10(1) Agreement of Modification and Severance of Mortgage (the "Mortgage Splitter Agreement"), dated as of May 1, 1994,
among the Partnership, the IDA and the Collateral Agent
10.10.11(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May 1, 1994, in the principal amount of $9,099,000 given
by the Partnership and the IDA to the Collateral Agent
10.10.12(1) Leasehold Mortgage (Substitute Mortgage No. 2), dated as of May 1, 1994, in the principal amount of $43,000,000 given
by the Partnership and the IDA to the Collateral Agent
10.10.13(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May 1, 1994, in the principal sum of $16,601,000 given by
the Partnership and the IDA to the Collateral Agent
10.10.14(1) Leasehold Mortgage (Gap Mortgage No. 2) in the principal amount of $42,199,000, dated as of May 1, 1994, given by the
Partnership and the IDA to the Collateral Agent
10.10.15(1) Leasehold Mortgage, Security Agreement and Fixture Financing Statement (the "Chase Mortgage"), dated as of May 1,
1994, given by the Partnership and the IDA to the Collateral Agent
10.10.16(1) Amended and Restated Security Agreement and Assignment of Contracts (the "Security Agreement"), dated as of May 1,
1994, made by the Partnership in favor of the Collateral Agent
10.10.17(1) Pledge and Security Agreement (the "Partnership Pledge Agreement"), dated as of May 1, 1994, from the Partnership in
favor of the Collateral Agent
10.10.18(1) Security Agreement (the "Company Security Agreement"), dated as of May 1, 1994, from the Company in favor of the
Collateral Agent
10.10.19(1) Intercreditor Agreement, dated as of May 1, 1994, among the Trustee, the Credit Bank, the Funding Corporation, the
Partnership, the Collateral Agent and certain other parties
10.10.20(1) Purchase Agreement and Transfer Supplement, dated as of May 1, 1994, among Chase, Dresdner, Yasuda, the Funding
Corporation and the Partnership
10.11 Other Material Project Contracts
10.11.1(1) Purchase Agreement, dated April 29, 1994, among the Funding Corporation, the Partnership, CS First Boston Corporation,
Chase Securities, Inc. and Morgan Stanley & Co. Incorporated
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
21(1) Subsidiaries of the Funding Corporation and Partnership
99 Additional Exhibits
99.1 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350 dated March 28, 2003
99.2 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350 dated March 28, 2003
99.3 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350 dated March 28, 2003
99.4 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350 dated March 28, 2003
__________
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 28, 2003 /s/ THOMAS E. LEGRO
----------------------------------
Name: Thomas E. Legro
Title: Vice President, Controller, Chief
Accounting Officer and Director
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 28, 2003
- ----------------------
P. Chrisman Iribe
/s/ THOMAS E. LEGRO Vice President, Controller, March 28, 2003
- ---------------------- Chief Accounting Officer
Thomas E. Legro and Director
/s/ SANFORD L. HARTMAN Secretary and Director March 28, 2003
- -----------------------
Sanford L. Hartman
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SELKIRK COGEN FUNDING
CORPORATION
Date: March 28, 2003 /s/ THOMAS E. LEGRO
-----------------------------------
Name: Thomas E. Legro
Title: Vice President, Controller, Chief
Accounting Officer and Director
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 28, 2003
- ----------------------
P. Chrisman Iribe
/s/ THOMAS E. LEGRO Vice President, Controller March 28, 2003
- -------------------- Chief Accounting Officer
Thomas E. Legro and Director
/s/ SANFORD L. HARTMAN Secretary and Director March 28, 2003
- -----------------------
Sanford L. Hartman
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this Annual Report on Form 10-K of Selkirk Cogen Partners,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ P. CHRISMAN IRIBE
_______________________
P. Chrisman Iribe
President
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen
Partners, L.P.
CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, Thomas E. Legro, certify that:
1. I have reviewed this annual report on Form 10-K of Selkirk Cogen Partners,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ THOMAS E. LEGRO
______________________________
Thomas E. Legro
Vice President, Controller and
Chief Accounting Officer
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen Partners, L.P.
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this annual report on Form 10-K of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ P. CHRISMAN IRIBE
__________________________________
P. Chrisman Iribe
President
Selkirk Cogen Funding Corporation
CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, Thomas E. Legro, certify that:
1. I have reviewed this annual report on Form 10-K of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 28, 2003
/s/ THOMAS E. LEGRO
___________________________________
Thomas E. Legro
Vice President, Controller and Chief
Accounting Officer
Selkirk Cogen Funding Corporation