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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 8-K
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of Earliest Event Reported): August 31, 1998
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
Delaware 51-0324332
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 788-3000
(Registrant's telephone number, including area code)
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ITEM 5. OTHER EVENTS
On August 31, 1998 Selkirk Cogen Partners, L.P. ("Selkirk" or the "Partnership")
and Niagara Mohawk Power Corporation ("Niagara Mohawk") consummated the
transactions relating to the amendment and restatement of the existing power
purchase agreement between the Partnership and Niagara Mohawk, pursuant to the
Master Restructuring Agreement dated as of July 9, 1997, as amended, among
Niagara Mohawk, the Partnership and certain other independent power producers
(the "MRA"). As contemplated by the MRA, on that date (i) the Partnership
notified Niagara Mohawk of the Partnership's determination that the requirements
of the Partnership's Trust Indenture, dated as of May 1, 1994 (the "Indenture"),
with respect to the restructuring of certain project contracts relating to the
operation of Unit 1 of the Selkirk facility had been satisfied; (ii) the Amended
and Restated Power Purchase Agreement, dated as of July 1, 1998, between the
Partnership and Niagara Mohawk became effective; and (iii) Niagara Mohawk made
certain payments into the Partnership's Project Revenue Fund maintained at
Bankers Trust Company, as Depositary Agent under the May 1, 1994 Deposit and
Disbursement Agreement. In addition, the Partnership has delivered notices to
Paramount Resources Limited ("Paramount") and TransCanada Pipelines Limited
("TransCanada") that the Second Amended and Restated Gas Purchase Contract,
dated as of May 6, 1998, between the Partnership and Paramount, and the Amending
Agreement to Gas Transportation Contract, dated as of July 20, 1998, between the
Partnership and TransCanada have become effective. The above-described
transactions are referred to herein as the "Unit 1 Restructuring."
Also on August 31, 1998 the Partnership forwarded to Bankers Trust Company, as
Trustee, the statement of its authorized representative (the "Selkirk Officer's
Certificate") certifying that, among other things, the implementation of the
Unit 1 Restructuring could not reasonably be expected to result in a Material
Adverse Change (as defined in the Indenture) and, after giving effect to such
transactions, the minimum annual Projected Debt Service Coverage Ratio (as
defined in the Indenture) will exceed 1.5:1 and the average annual Projected
Debt Service Coverage Ratio for the remaining term of the bonds issued under the
Indenture (the "Bonds") will exceed 1.75:1. The Selkirk Officer's Certificate
was accompanied by written certifications required to be made under the
Indenture by R.W. Beck, Inc. ("R.W. Beck"), as the Independent Engineer, and
C.C. Pace Consulting, L.L.C., as the Gas Consultant (in each case as defined in
the Indenture). The Selkirk Officer's Certificate and the related certifications
of the Independent Engineer dated as of August 31, 1998 (the "Independent
Engineer's Certificate"), and the certifications of the Gas Consultant dated
August 28, 1998 are filed as Exhibits to this Report on Form 8-K.
The projections from which Projected Debt Service Coverage Ratios are derived
(the "Projected Operating Results") are set forth at Attachment B to the
Independent Engineer's Certificate, have been prepared by the Partnership and
reviewed and accepted by R.W. Beck on the basis of present knowledge and
assumptions which the Partnership and R.W. Beck believe to be reasonable. For
purposes of preparing the Projected Operating Results, certain assumptions were
made, of necessity, with respect to general business and economic conditions,
the revenues the Partnership will receive for electric energy and steam and the
resale of natural gas, the cost to the Partnership of obtaining natural gas
supplies and several other material contingencies and other matters that are not
within the control of the Partnership nor R.W. Beck and the outcome of which
cannot be predicted. These assumptions and the other assumptions used in such
analysis and identified in the notes to the Projected Operating Results are
inherently subject to significant
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uncertainties, and actual results will be different, perhaps materially, from
those projected. Accordingly, the Projected Operating Results are not
necessarily indicative of current values or future performance and none of the
Partnership, Selkirk Cogen Funding Corporation, R.W. Beck or any other Person
assumes any responsibility for their accuracy. While these assumptions are based
on currently known information and are dependent upon future events, the
Partnership and R.W. Beck have each certified to the Trustee, as required under
the Indenture, that the assumptions upon which the subject Projected Debt
Service Coverage Ratios are based are reasonable and materially consistent with
the Partnership's project agreements and historical operating results. None of
the Partnership, Selkirk Cogen Funding Corporation, R.W. Beck or any other
Person have any obligation, nor do they intend, to provide the holders of the
Bonds with updated reports or revised projections comparing the Projected
Operating Results and actual operating results later achieved by the
Partnership.
On August 31, 1998, the Partnership received written notice from Standard &
Poor's Corporation ("S&P") that, after giving effect to the Unit 1
Restructuring, S&P affirmed its "BBB-" rating of the Selkirk Cogen Funding
Corporation's Bonds and removed the rating from CreditWatch. On August 27, 1998,
the Partnership received written notice from Moody's Investors Service, Inc.
("Moody's") that, after giving effect to the Unit 1 Restructuring, Moody's
affirmed its "Baa3" rating of the Selkirk Cogen Funding Corporation's Bonds,
changed the outlook of the Bonds Due 2007 from "negative" to "stable" and has
not changed its previous "negative outlook" with respect to the Bonds Due 2012.
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND
EXHIBITS.
(c) Exhibits Required by Item 601 of Regulation S-K.
(i) Amended and Restated Power Purchase Agreement , dated as of July
1, 1998, between Selkirk Cogen Partners, L.P. and Niagara Mohawk
Power Corporation
(ii) Mutual General Release and Agreement, dated as of July 1, 1998,
between Selkirk Cogen Partners, L.P. and Niagara Mohawk Power
Corporation
(iii) Second Amended and Restated Gas Purchase Contract, dated as of
May 6, 1998, between Selkirk Cogen Partners, L.P. and Paramount
Resources Limited
(iv) Amending Agreement, dated as of July 20, 1998, between
TransCanada Pipelines, Limited and Selkirk Cogen Partners, L.P.
(v) Officer's Certificate of Selkirk Cogen Partners, L.P., dated
August 31, 1998, delivered to Bankers Trust Company, as Trustee
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(vi) Independent Engineer's Certificate of R.W. Beck, Inc., dated as
of August 31, 1998, delivered to Bankers Trust Company, as
Trustee
(vii) Gas Consultant's Certificate of C.C. Pace Consulting, L.L.C.,
dated August 28, 1998, delivered to Bankers Trust Company, as
Trustee
(viii) Press Release of Selkirk Cogen Partners, L.P., dated August 31,
1998
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN PARTNERS, L.P.
Date: September 16, 1998 /s/JMC SELKIRK, INC.
------------------------
General Partner
Date: September 16, 1998 /s/JOHN R. COOPER
-------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN FUNDING
CORPORATION
Date: September 16, 1998 /s/ JOHN R. COOPER
-----------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
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EXHIBIT INDEX
Exhibit No. Description
10.1 Amended and Restated Power Purchase Agreement, dated as of
July 1, 1998, between Selkirk Cogen Partners, L.P. and
Niagara Mohawk Power Corporation
10.2 Mutual General Release and Agreement, dated as of July 1,
1998, between Selkirk Cogen Partners, L.P. and Niagara
Mohawk Power Corporation
10.3 Second Amended and Restated Gas Purchase Contract, dated as
of May 6, 1998, between Selkirk Cogen Partners, L.P. and
Paramount Resources Limited
10.4 Amending Agreement, dated as of July 20, 1998, between
TransCanada Pipelines, Limited and Selkirk Cogen Partners,
L.P.
99.1 Officer's Certificate of Selkirk Cogen Partners, L.P., dated
August 31, 1998, delivered to Bankers Trust Company, as
Trustee
99.2 Independent Engineer's Certificate of R.W. Beck, Inc., dated
as of August 31, 1998, delivered to Bankers Trust Company,
as Trustee
99.3 Gas Consultant's Certificate of C.C. Pace Consulting,
L.L.C., dated August 28, 1998, delivered to Bankers Trust
Company, as Trustee
99.4 Press Release of Selkirk Cogen Partners, L.P., dated August
31, 1998
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AMENDED AND RESTATED AGREEMENT
THIS AMENDED AND RESTATED AGREEMENT, made and entered into as of July
1, 1998, by and between Selkirk Cogen Partners, L.P., a Delaware limited
partnership (hereinafter referred to as SELLER), with offices at Boston,
Massachusetts, and NIAGARA MOHAWK POWER CORPORATION, a domestic corporation
(hereinafter referred to as NIAGARA) with its office and principal place of
business at Syracuse, New York.
W I T N E S S E T H :
WHEREAS, SELLER (by assignment) and NIAGARA are parties to an
Agreement dated December 7, 1987, as amended by an Amendment dated December 14,
1989, the Second Amendment dated January 25, 1990, the Third Amendment dated
October 23, 1992, an Agreement dated March 31, 1994, and the Fourth Amendment
dated June 26, 1996 (collectively referred to as the "Original Agreement").
(Capitalized terms not otherwise defined herein shall have the meaning set forth
in Schedule A to this AGREEMENT.)
WHEREAS, SELLER will own and operate an electric generating plant
(hereinafter referred to as "Phase I") in Selkirk, New York, with an initial
capacity of approximately 79 megawatts, and with expected annual production of
approximately 625,000 megawatt-hours initially, so arranged that the ELECTRICITY
generated therein can be delivered to the electric transmission system of
NIAGARA with which it will be
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physically connected at the Receiving Point as set forth in the Phase I
Interconnection Agreement; and
WHEREAS, NIAGARA, in the conduct of its business, can make use of the
amount of ELECTRICITY which SELLER may generate at Phase I; and
WHEREAS, SELLER represents that, prior to commencement of operation of
Phase I, Phase I is or will become: (1) a qualifying facility (hereinafter
referred to as "QF") as defined in the Public Utility Regulatory Policies Act of
1978 (hereinafter referred to as "PURPA"); 16 USCS Section 824a-3 et seq., 18
CFR Section 292.205 et seq. ) and (2) a cogeneration facility as defined in
Section 2.2-a of the New York State Public Service Law (hereinafter referred to
as "2-a"); and
WHEREAS, SELLER represents that, if required, Phase I is or will be
qualified for exemption from the prohibitions set forth in the Power Plant &
Industrial Fuel Use Act hereinafter referred to as "FUA"); 42 USCS Section 8301,
et seq., particularly Sections 8311, 8312 and 8322(c), 10 CFR Section 500 et
seq., particularly Section 503.37 et seq.); and
WHEREAS, SELLER represents that, if required, Phase I will be
certified as a MAJOR STEAM ELECTRIC FACILITY as defined in Article VIII of the
New York Public Service Law (Vol. 47 McKinney's Consolidated Laws of New York,
Section 140 et seq.); provided, however, SELLER has the right to terminate this
AGREEMENT upon a finding by the Public Service Commission of the State of New
York ("COMMISSION") or
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the New York State Board on Electric Generation, Siting and the Environment that
Phase I is subject to Article VIII; and
WHEREAS, SELLER and NIAGARA desire to amend the Original Agreement on
the terms and conditions set forth in this AGREEMENT.
NOW, THEREFORE, in consideration of the premises and covenants
hereinafter set forth, the Parties hereto have agreed and do hereby mutually
agree as follows:
FIRST: Prior to commencement of the operation of Phase I, SELLER shall
certify to NIAGARA or deliver to NIAGARA other evidence in writing satisfactory
to NIAGARA that Phase I (1) is a QF as defined in PURPA (15 USCS Section 824a-3,
et seq., 18 CFR Section 292.205, at et seq.), (2) is a cogeneration facility as
defined in 2-a, and (3) that, if required, Phase I has qualified for exemption
from the prohibitions set forth in the FUA in accordance with Section 8322 of
the FUA and 10 CFR Section 503.37 et seq.
As of the Effective Date, NIAGARA shall have no contractual right and
shall waive any other right which it might have under state or federal law to
demand information from SELLER, or any other person, including but not limited
to any Governmental Authority, with respect to SELLER's status as a qualifying
facility ("QF Status"). SELLER shall have the right, but not the obligation, in
its sole discretion to obtain and/or maintain its QF Status under federal or New
York law (including compliance with 2-a and/or PURPA). NIAGARA's rights and
obligations, including without limitation its obligation
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to pay for ELECTRICITY produced by SELLER as set forth hereunder, shall continue
as a matter of contractual right regardless of whether the SELLER maintains its
QF Status. Any failure by SELLER to comply with the requirements applicable to
QF Status under New York law (including compliance with 2-a) shall have no
adverse impact on SELLER under this AGREEMENT. In the event SELLER wishes to
qualify or perform as an Exempt Wholesale Generator under Section 32 of PUHCA
and the FERC's regulations promulgated thereunder, as the same may be amended,
modified or restated from time to time, NIAGARA shall cooperate with (including,
without limitation, by providing consents and affidavits), and shall not take
any action to oppose, impede or subvert, SELLER's efforts to obtain appropriate
regulatory exemptions and approvals, including market-based rate approval.
Except to the extent that the contract prices under this AGREEMENT are or may be
based thereon, during the term of the AGREEMENT, SELLER (i) shall waive any
statutory right it may have under Section 66-c of NYPSL pursuant to which SELLER
may demand a 6(cent) per kWh minimum power purchase rate from NIAGARA, and (ii)
shall waive, for itself and for the successors and assigns of Phase I with
respect to Phase I, any statutory right it may have under PURPA or NYPSL to
require NIAGARA to enter into a power purchase contract or otherwise take the
output of Phase I; provided, however, that until the end of the Proxy-Market
Price Period NIAGARA agrees, at SELLER's request, to act as agent for SELLER
(or, if necessary to effectuate such sales to the New York Power Pool, by
purchase and resale of SELLER's capacity and/or energy, at no cost to NIAGARA),
for the sale on up to a monthly basis of the Phase I's ELECTRICITY to the New
York Power Pool or any third party, in each case on a nondiscriminatory basis
with
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respect to NIAGARA's or any third party's capacity and energy, at no cost
to SELLER. NIAGARA agrees to use its Reasonable Best Efforts to effect such
sales on the most favorable terms, including price, to SELLER giving
consideration to the quantity, term and market conditions prevailing at the time
of sale. Nothing contained herein shall be construed to constitute a waiver by
the SELLER of any other rights it may have under PURPA, NYPSL or applicable law,
including rights with respect to back-up services, interconnection, reactive
power or other similar rights, whether or not a contract is required or
desirable.
SECOND: NIAGARA acknowledges prior receipt of the DEPOSIT on November
25, 1988 in the amount of $10 per KW of capacity, i e., $790,000.00. Not later
than the last day for commencement of construction specified by Paragraph THIRD
of the AGREEMENT, i.e., May 25, 1990, SELLER shall post with NIAGARA an
additional deposit (hereinafter referred to as the "FIRST ADDITIONAL DEPOSIT")
of $5 per KW of capacity, i e., $395,000.00. The DEPOSIT and FIRST ADDITIONAL
DEPOSIT (hereinafter referred to collectively as the "DEPOSITS") shall be posted
in the form of cash or, at SELLER's option, an irrevocable letter of credit from
a financial institution rated at least AA for a term that extends ten (10) days
past the scheduled date of commercial operation of Phase I. If all or any part
of the DEPOSITS are made in cash, NIAGARA shall hold such cash in escrow with
the Marine Midland Bank, N.A., or another bank chosen by NIAGARA and reasonably
acceptable to SELLER, and invest it in the Certificate of Deposit or U.S.
Treasury Bill of the SELLER's choice; provided, however, the instrument must
mature on or before the scheduled date of commercial operation of
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Phase I. The DEPOSITS plus any interest earned in accordance with the
COMMISSION's Order Establishing Milestones and Soliciting Comments, issued and
effective May 25, 1988, will be refunded within thirty (30) days of the later of
Phase I's initial operation date, as said date is determined in accordance with
the provisions of Paragraph ELEVENTH, or the maturation date, if pertinent, of
any Certificate of Deposit or U.S. Treasury Bill used to satisfy the deposit
requirements, provided that SELLER has met the commencement and completion of
construction milestones set forth in Paragraph THIRD. In the event that SELLER
fails to post the DEPOSITS as required or otherwise fails to comply with the
requirements of this Paragraph, this AGREEMENT shall at the option of NIAGARA
become null and void without liability of any description, kind or nature
whatever by NIAGARA to SELLER and the DEPOSITS, if made, shall be retained by
NIAGARA and any interest accrued shall be returned to SELLER.
THIRD: SELLER must commence on-site construction of Phase I no later
than twenty-four (24) months after the approval of the Original Agreement
pursuant to Paragraph TWENTIETH, thereafter continuously pursue such
construction in a good faith effort to complete construction and thereafter
place Phase I in operation no later than sixty (60) months after such approval.
For the purposes of this AGREEMENT, SELLER shall be deemed to have commenced
on-site construction when: (1) activity is coordinated, continuous, and reaches
a sufficient degree of intensity, (2) active construction efforts are made
related to major project features, and (3) actual physical construction of those
features begins. Commencement of construction does not occur with mere site
preparation or equipment design which are insufficient to meet this test.
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In the event that SELLER is unable to comply with the requirements of
this Paragraph THIRD, this AGREEMENT shall at the option of NIAGARA become null
and void without liability of any description, kind or nature whatever by
NIAGARA to SELLER, and the DEPOSITS described in Paragraph SECOND shall be
forfeited, and any interest accrued shall be returned to SELLER. Notwithstanding
the above, in the event SELLER is unable to comply with the deadline for the
commencement of construction, as defined in this Paragraph THIRD, SELLER may, in
addition to the deposit posted pursuant to the COMMISSION's ORDER and defined in
Paragraph SECOND, post additional cash deposits with NIAGARA for each month of
proposed or actual delay in meeting said commencement of construction. In no
event shall the delay in commencing construction of Phase I be longer than
eighteen (18) months from the commencement of construction milestone as defined
in Paragraph SECOND.
Such additional deposit(s) payable to NIAGARA shall: (i) be in the
form of cash; (ii) be in the amount of $0.50/KW per month, i e., $39,500 per
month; and (iii) be posted in monthly increments on or before said milestone
date or any extensions thereof. Such additional deposits, if any, together with
the DEPOSITS provided for in Paragraph SECOND shall be known as the TOTAL
DEPOSIT.
In the event that SELLER is unable to comply with the operational
deadline set forth in this Paragraph THIRD, NIAGARA shall be entitled to draw
against the TOTAL DEPOSIT posted by SELLER as follows: NIAGARA shall be entitled
to a forfeiture of the TOTAL DEPOSIT in an amount equal to one-twelfth (1/12) of
the TOTAL DEPOSIT
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for each month of delay in operation beyond said milestone. In no event shall
such operational deadline be extended beyond one year from the initial
operational deadline. If SELLER has not commenced Commercial Operation, within
one (1) year from said operational deadline, this AGREEMENT shall at the option
of NIAGARA become null and void without liability of any description, kind or
nature whatever by NIAGARA to SELLER.
For purposes of this AGREEMENT, the "Date of Commercial Operation"
shall be hereinafter defined as that point in time when Phase I shall produce
ELECTRICITY continuously, as confirmed by SELLER. SELLER shall use all
reasonable efforts to reach commercial operation not later than
one-hundred-and-eighty (180) days after the first sale of ELECTRICITY to
NIAGARA.
FOURTH: SELLER shall deliver to NIAGARA and NIAGARA shall accept and
pay for ELECTRICITY produced at Phase I or otherwise provided hereunder, subject
to the terms and conditions of this AGREEMENT.
NIAGARA agrees that its obligation to accept and pay for ELECTRICITY
as provided herein shall in no event be subject to any curtailment of
electricity under the provisions of 18 C.F.R. ss. 292.304(f) (1997), or any
subsequent or similar rule or regulation adopted by the COMMISSION or the FERC,
or any rule or order of the COMMISSION, the FERC, or any other Governmental
Authority interpreting or applying those provisions or authorizing NIAGARA to
reserve any rights under those provisions.
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FIFTH: SELLER shall deliver the ELECTRICITY to the system of NIAGARA
at approximately 115,000 volts, 60 Hertz and 3 Phase. The installation of the
electrical connections and the operation of Phase I must meet or exceed the
requirements of NIAGARA's ESB #756, a copy of which is incorporated herein by
reference. SELLER shall deliver the ELECTRICITY to the Delivery Point.
SELLER shall have the right, subject to NIAGARA's consent, which shall
not be unreasonably withheld, to construct, at SELLER's cost, alternative
interconnection equipment upon one (1) year's written notice to NIAGARA. Such
alternative interconnection, if any, shall deliver the ELECTRICITY to the system
of NIAGARA at a voltage to be mutually agreed upon by NIAGARA and SELLER, 60
Hertz and 3 Phase, and shall be constructed and operated so as to meet or exceed
the requirements of the version of NIAGARA's ESB #756 in effect at the time the
notice required by this Paragraph FIFTH is provided to NIAGARA. In the event
that such alternate interconnection equipment is constructed, the Receiving
Point under the Phase I Interconnection Agreement shall be as mutually agreed by
NIAGARA and SELLER.
SIXTH: NIAGARA's acceptance of and obligation to pay for the Delivered
Energy Quantity, the Delivered Capacity Quantity and the Call Option Quantity
under Section II of ATTACHMENT I for ELECTRICITY produced may be suspended for
any period(s) of time during which, for reasons of necessary maintenance,
repair, service, system emergency, safety, or similar actions, NIAGARA's
transmissions system is temporarily physically unable to accept such
ELECTRICITY. If necessary, and solely for the reasons
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set forth above, NIAGARA may order that Phase I's generating facility be
disconnected from NIAGARA's transmission system.
NIAGARA shall give reasonable notice under the circumstances of the
need for such disconnection to employees or agents of SELLER designated from
time to time by SELLER to receive such notice. Upon receipt of such notice,
SELLER shall carry out the required action without undue delay. Upon written
request of SELLER, NIAGARA shall promptly inform SELLER, in writing, of the
reasons for any disconnection.
During any period of disconnection, NIAGARA shall use its best efforts
to restore NIAGARA's capability to accept delivery of ELECTRICITY as promptly as
possible.
NIAGARA shall inform SELLER of any planned outages to the facilities
serving Phase I and use its best efforts to schedule any planned outages upon
consultation with the SELLER and commensurate with SELLER's schedule for planned
maintenance or other outages.
NIAGARA shall bear any costs incurred by it in connection with any
such disconnection or reconnection. All deliveries of ELECTRICITY which are
subject to any such suspension may be rescheduled at the option of the SELLER.
SEVENTH: In addition to the Parties' obligations under Attachment I,
the following shall apply to the Parties' rights and obligations with respect to
ELECTRICITY:
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(A) During the Proxy-Market Price Period, the following shall apply to
SELLER's obligation to deliver, and NIAGARA's obligation to take and pay for
ELECTRICITY:
1. At the option of SELLER, SELLER shall have the right to sell and
deliver, and NIAGARA shall take and pay for, ELECTRICITY as
follows: (i) energy up to the specified Monthly Contract Quantity
for the applicable period plus the Overgeneration Amount, and
(ii) capacity, which is subject to both seasonal variation and
degradation, associated with the Monthly Contract Quantity, in
each case, for each Interval during the immediately succeeding
Settlement Period.
2. The right of SELLER to sell and deliver ELECTRICITY to NIAGARA
hereunder shall be limited to energy and associated capacity as
described in Paragraph SEVENTH, Section A.1. SELLER shall not
object to NIAGARA's inclusion of all capacity associated with the
Notional Quantity of ELECTRICITY pursuant to the terms hereof as
capacity available to NIAGARA for regulatory purposes.
3. SELLER shall have the right to sell and deliver ELECTRICITY to
NIAGARA for periods ranging for a minimum period of time of one
hour to a maximum period of one month. On or prior to 12:00 p.m.
noon of the Business Day two days prior to the first day of the
month, SELLER shall provide to NIAGARA a schedule showing, on an
hour-by-hour basis, the
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projected deliveries of ELECTRICITY to NIAGARA for the following
calendar month. SELLER shall have the right to update such
schedule on an hourly basis by providing notice of the change, in
writing or through electronic telecommunications, no less than
thirty minutes prior to the start of the hour in which the change
to the schedule is to be effected.
4. If SELLER determines not to exercise its rights to sell and
deliver ELECTRICITY to NIAGARA in accordance with Paragraph
SEVENTH, Section A.1, SELLER may sell and deliver such
ELECTRICITY to third parties, provided SELLER has first
offered to sell such ELECTRICITY from Phase I up to the
Monthly Contract Quantity for the applicable period to NIAGARA
at the Market Energy Price, and, if applicable, the Market
Capacity Price on the following schedule:
(a) ELECTRICITY sales for one hour up to and
including one week - SELLER shall notify NIAGARA of
such request by 9:00 am two Business Days prior to
the start of the ELECTRICITY sale and NIAGARA shall
respond no later than four hours from such request;
(b) ELECTRICITY sales for more than one week up to
and including one month - SELLER shall notify NIAGARA
of such request by 9:00 am three Business Days prior
to the start of the ELECTRICITY sale and NIAGARA
shall respond no later than one Business Day from
such request;
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(c) ELECTRICITY sales for more than one month and up
to and including twelve months SELLER shall notify
NIAGARA of such request by 9:00 am five Business Days
prior to the start of the ELECTRICITY sale and
NIAGARA shall respond no later than three Business
Days from such request;
(d) ELECTRICITY sales for more than twelve months -
SELLER shall notify NIAGARA of such request by 9:00
am seven Business Days prior to the start of the
ELECTRICITY sale and NIAGARA shall respond no later
than five Business Days from such request.
All notifications by SELLER and responses by NIAGARA described
herein shall be made during normal business hours (8:00 am to
5:00 p.m.). Notwithstanding the above, notification by SELLER
and response by NIAGARA for the sale of ELECTRICITY to a third
party shall be completed prior to the FERC approved
notification period for market participants to submit
day-ahead bids to the ISO/PE.
(B) In addition, and without prejudice, to SELLER's rights in Section
(A) above, the following shall apply with respect to NIAGARA's right to schedule
ELECTRICITY from the SELLER during the S.C.-6 Price Period which comprises part
of the Proxy-Market Price Period:
1. At the option of NIAGARA, NIAGARA shall have the right ("Call
Option") solely during the S.C.-6 Price Period, and subject to
the
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conditions stated in this Paragraph SEVENTH, Section B, to
schedule delivery of ELECTRICITY from Phase I up to the Monthly
Contract Quantity ("Call Option Quantity"), provided that SELLER
has not scheduled such ELECTRICITY for sale and delivery to
NIAGARA or any other party pursuant to Section (A) of this
Paragraph SEVENTH. SELLER shall be obligated to sell and deliver
the Call Option Quantity to NIAGARA at the Delivery Point,
provided, however, that SELLER shall be excused from this
obligation if Phase I is unavailable due to outages for any
reason (including, but not limited to, the full or partial
unavailability of Phase I due to an insufficiency or inadequacy
of gas supply or gas transportation for any reason including but
not limited to unavailability at the Call Gas Price).
2. In the event NIAGARA exercises its Call Option, SELLER may, at
its option, sell and deliver, and NIAGARA shall take and pay for,
ELECTRICITY tendered at the Delivery Point which is in excess of
the Call Option Quantity up to the Effective DMNC ("Excess
Energy").
3. The price NIAGARA shall pay for the Call Option Quantity and
Excess Energy shall be the Call Energy Price which in each
applicable Interval shall be the higher of (1) the S.C.-6 Rate,
and (2) Phase I's Variable Energy Cost.
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4. NIAGARA must comply with the following notice obligations in
order to exercise its Call Option. On each day immediately
prior to the day on which NIAGARA desires to purchase
ELECTRICITY under the Call Option, NIAGARA must notify
SELLER no later than 10:00 a.m. of the Call Option Quantity
it requires for each Interval of the twenty-four (24) hour
period commencing at 12:01 a.m. of the following day and
ending at 12:01 a.m. of the next following day; provided
however, that in lieu of separate schedules for Saturday,
Sunday and Monday, not later than 10:00 a.m. on each
applicable Friday the amount of the Call Option Quantity for
each Interval of the seventy-two (72) hour period commencing
at 12:01 a.m. of the following Saturday and ending at 12:01
of the following Tuesday ("Schedule"). The Schedule run time
for Phase I shall be no less than twenty four (24) hours and
the maximum ramp rate shall be 800 kW per minute when
ramping up and 1600 kW per minute when ramping down.
5. SELLER shall have the right to sell and deliver Excess
Energy to NIAGARA for periods ranging from a minimum period
of one hour to a maximum period of twenty four (24) hours
during the Call Option period. On or prior to 12:00 p.m.
noon of the day SELLER receives NIAGARA's Schedule, SELLER
shall provide to NIAGARA a schedule showing, on an
hour-by-hour basis, the projected deliveries of Excess
Energy to NIAGARA for the following day. SELLER shall have
the
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right to update such schedule on an hourly basis by
providing notice of the change, in writing or through
electronic telecommunications, no less than thirty minutes
prior to the start of the hour in which the change to the
schedule is to be effected. SELLER's right to sell and
deliver the Excess Energy is in addition to its right to
sell and delivery the Overgeneration Amount to NIAGARA.
(C) Upon the expiration of the Proxy-Market Price Period and until the
term of this AGREEMENT expires, the following shall apply with respect to the
sale and delivery of ELECTRICITY:
1. During this period, NIAGARA shall have no obligation to take
and pay for ELECTRICITY under the Delivered Energy Payment
and Delivered Capacity Payment components of the Energy
Payment under Section II of ATTACHMENT I except to the
extent that NIAGARA elects to purchase ELECTRICITY pursuant
to its rights of first refusal described below.
2. During this period, SELLER shall not sell ELECTRICITY from
Phase I in any amount up to the Monthly Contract Quantity
for the applicable period to third parties, unless SELLER
shall first offer to sell and deliver such ELECTRICITY to
NIAGARA at the Market Energy Price, and, if applicable, the
Market Capacity Price and NIAGARA has declined the
opportunity to take and pay for such ELECTRICITY on
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the schedule set forth in Section A.4 of Paragraph SEVENTH.
SELLER shall not object to NIAGARA's inclusion of all
capacity associated with the Notional Quantity of
ELECTRICITY pursuant to the terms hereof as capacity
available to NIAGARA for regulatory purposes.
D. SELLER may, but is not required, to deliver energy and/or capacity
to NIAGARA at the Delivery Point from Phase I or Phase II or from any other
source arranged by SELLER, and such energy and/or capacity shall be deemed
ELECTRICITY hereunder, and further subject to SELLER's rights to assign this
AGREEMENT pursuant to the assignment provisions contained herein. The foregoing
sentence shall not be deemed to relieve SELLER of its obligations (i) to provide
NIAGARA with the Call Option Quantity in accordance with Section B of Paragraph
SEVENTH, or (ii) to perform the DMNC tests for Phase I in accordance with
Section VI of ATTACHMENT I. Any right or obligation of SELLER to provide
ELECTRICITY under this Paragraph SEVENTH to NIAGARA shall entitle SELLER to sell
and deliver to NIAGARA, and obligate NIAGARA to take and pay for, the
Overgeneration Amount.
E. ELECTRICITY in excess of the Monthly Contract Quantity for any
Interval, except for Excess Energy delivered with the Call Option Quantity,
shall not be subject to this AGREEMENT and, at the option of SELLER (including
the
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Excess Energy), may be sold to third parties without an obligation to offer such
energy and capacity to NIAGARA.
EIGHTH: SELLER shall have the right to shut down the operation of
Phase I or temporarily disconnect it from NIAGARA's system whenever and for such
periods of time as may be necessary for maintenance, repair, emergency or
safety. SELLER shall bear the cost of disconnection and reconnection, which
shall include the direct costs of personnel, including overhead, required to
accomplish such disconnection and reconnection, but which shall not include the
cost of replacement power.
NIAGARA and SELLER shall coordinate maintenance of Phase I in the
manner set forth on ATTACHMENT VIII.
NINTH: (A) After netting the amounts due pursuant to the payment
provisions of this AGREEMENT, SELLER shall provide NIAGARA with a Notice of any
payments due under this AGREEMENT for the preceding Settlement Period on or
before the 5th day of each calendar month, unless SELLER and NIAGARA otherwise
agree. Payments shall be due on the Payment Date immediately following the
associated Settlement Period. NIAGARA shall pay SELLER on or before the Payment
Date the amounts due under a Notice by wire transfer to SELLER's following
account, or such other account that SELLER may designate by written notice to
NIAGARA:
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Banker's Trust Company
Four Albany Street
New York, NY 10006
ABA #: 021-001-033
Account Name: Selkirk Cogen Project Revenue Fund #12103
Account #: _______________
SELLER shall pay NIAGARA on or before the Payment Date the amounts due under a
Notice by wire transfer to NIAGARA's following account, or such other account
that NIAGARA may designate by written notice to SELLER:
Citibank
399 Park Avenue
New York, NY 10022-4699
ABA #: 021-000-089
Account Name: Niagara Mohawk Power Corporation
Account #: ________________
Any amount remaining unpaid after the time it is due and not disputed in good
faith shall thereafter be subject to a late payment charge equal to the prime
rate for U.S. currency as published from time to time under "Money Rates" in The
Wall Street Journal multiplied by the unpaid amount calculated for the period
from and including the Payment Date in which it was due to the date it is
actually paid.
If either Party, in good faith, disputes any part of any Notice of a
payment obligation, that Party shall provide a written explanation of the basis
for such dispute and the undisputed portion of the net payment obligations set
forth in such Notice shall be paid by the Party obligated to pay such amounts no
later than the applicable Payment Date. Any adjustment under this Paragraph
shall bear interest at the prime
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rate for U.S. currency as published from time to time under "Money Rates" in The
Wall Street Journal, from and including the Payment Date any such underpayment
or overpayment was originally due but excluding the date on which such
underpayment or overpayment is finally settled by the Parties hereto, or in the
event the Parties hereto are unable to settle such matter, such matter shall be
settled by an independent nationally recognized public accounting firm mutually
selected by the Parties whose determination shall be final and binding on the
Parties hereto and whose fees and expenses shall be borne by the Party found to
be at substantial fault by such independent public accounting firm. If the
independent public accounting firm finds that there is no substantial fault on
the part of either Party, each Party shall be responsible for its own fees and
expenses. No Notice (or payment obligation thereunder) shall be subject to this
Paragraph unless a notice of dispute is given with respect thereto within one
year of the Payment Date applicable to such Notice.
(B) Commencing on the Effective Date and throughout the term of this
AGREEMENT, NIAGARA will pay SELLER , or SELLER will pay NIAGARA, as appropriate,
the monthly payment set forth in ATTACHMENT I. NIAGARA and SELLER agree that on
or before January 15 of each year during the term of the contract, NIAGARA and
SELLER may review any amounts paid pursuant to this AGREEMENT during the prior
year to ensure that the amounts paid following the Effective Date were in
accordance with ATTACHMENT I and this Paragraph NINTH. In the event that either
Party shall discover an error, the Party discovering the error shall notify the
other Party. Such notice shall specify the amount overpaid
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or underpaid by a Party in each billing period during the prior year. In the
event a Party was overpaid, that Party shall promptly refund any overpayments to
the other Party. In the event a Party was underpaid, the other Party shall
promptly make up any underpayments. Such annual review and true-up of payments
shall not limit either Party's right to monitor the amounts paid versus the
amounts due, seek proper payments or refunds upon or after the discovery of
billing errors at other times, or impose any late payment charge expressly
provided for by this AGREEMENT to the extent permitted in Paragraph NINTH.
(C) After the Effective Date, the monthly Notice provided by SELLER to
NIAGARA shall reflect adjustments for the following payment obligations incurred
in the preceding Settlement Period:
1. Netting for Cost Changes. On each Payment Date, NIAGARA shall be
obligated to pay to SELLER (to the extent that such number is
positive) and SELLER shall be obligated to pay NIAGARA (to the extent
that such number is negative and in such case the absolute value of
such number) (x) the difference between (a) any increase as compared
to the costs under SELLER's contractual arrangements with NIAGARA as
of January 1, 1997 during the associated Settlement Period in (i)
NIAGARA's local distribution system gas transportation and fixed and
variable charges and retainages actually incurred by SELLER, and (ii)
electrical interconnection costs and costs associated with industry
reliability standards actually incurred by SELLER (including without
limitation any increase in costs related to SELLER's compliance with
ESB
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#756), provided that such costs shall be direct in nature and
exclusive of general and administrative expenses, and (b) any
decreases as compared to the costs under SELLER's contractual
arrangements with NIAGARA as of January 1, 1997 during the associated
Settlement Period in those costs listed in (i) and (ii) above, and (y)
any increase as compared to the costs under SELLER's contractual
arrangements with NIAGARA as of January 1, 1997 during the associated
Settlement Period in costs incurred by SELLER caused by changes in
federal, state or local laws, rules or regulations; provided that this
clause (y) shall only be effective during the Proxy-Market Price
Period and any periods thereafter during which like adjustments in
costs are also recovered by any entity that owns any of NIAGARA's
non-nuclear generating assets.
2. Certain Other Cost Additions. On each Payment Date, NIAGARA shall be
obligated to pay to SELLER any increase as compared to the costs under
SELLER's contractual arrangements with NIAGARA as of January 1, 1997 in
electrical transmission costs or access or other charges, which are
actually incurred by SELLER during the associated Settlement Period
while physically delivering electricity to (x) NIAGARA during the
Proxy-Market Price Period or (y) an ISO/PE following the Proxy-Market
Price Period; provided that this clause (y) shall only be effective
during the periods when like increases in costs or charges are then
also recovered by any entity that owns any of NIAGARA's non-nuclear
generating assets.
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3. Reactive Power, Voltage Support Services and Line-Loss Charges.
NIAGARA and SELLER acknowledge that the contract prices under this
AGREEMENT do not include charges for reactive power, voltage support
services or line-losses. In the event that NIAGARA's tariffs require
SELLER to pay NIAGARA for reactive power or line-losses during periods
when the SELLER's generating facilities are generating electricity, the
contract prices under this AGREEMENT for each applicable Settlement
Period will be equitably increased in an amount equal to all reactive
power charges and/or line-loss charges or costs actually incurred by
SELLER during the associated Settlement Period. In addition, in the
event (i) under any ISO tariff, SELLER is required to provide voltage
support services, as defined by such ISO tariff, NIAGARA shall pay to
SELLER on each Payment Date any and all voltage support service
payments made by the ISO to NIAGARA in the associated Settlement Period
which are attributable to the voltage support services provided by
SELLER, and (ii) the ISO charges SELLER for any line-losses, the
contract prices under this AGREEMENT will be equitably increased in an
amount equal to all such line-loss charges incurred by SELLER during
the associated Settlement Period.
During the full term of this AGREEMENT, SELLER agrees to keep Phase I
insured in accordance with the provisions of ATTACHMENT VI hereto.
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TENTH: SELLER and NIAGARA shall install, own and maintain their
respective interconnection facilities in accordance with the Phase I
Interconnection Agreement and the Phase II Interconnection Agreement.
If, at some future time, it becomes necessary for NIAGARA to relocate
or rearrange its transmission system to which Phase I is connected, NIAGARA
shall advise SELLER one year in advance in writing. If such relocation or
rearrangement is ordered or required by a Governmental Authority, NIAGARA shall
give prior written notice to SELLER equal in time to the notice given NIAGARA by
such Governmental Authority, to the extent possible. NIAGARA shall consult with
SELLER on the new facilities that NIAGARA shall propose to reestablish the
connection. Such new facilities shall be reasonably satisfactory to SELLER and,
at a minimum, shall provide SELLER with at least as much output capacity as with
the prior connection facilities. NIAGARA shall bear the full cost and expense of
reestablishing the connection to SELLER. NIAGARA shall use its best efforts to
minimize the duration of any disruption to SELLER's service during the
relocation or rearrangement of NIAGARA's transmission facilities.
If, at some future time, NIAGARA determines it is necessary to retire
or abandon its transmission systems to which Phase I is connected, NIAGARA shall
advise SELLER, at least one year in advance, in writing, indicating NIAGARA's
annual costs of transmission facilities dedicated exclusively to accommodate the
output of Phase I. SELLER shall then have the option of paying NIAGARA for these
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annual costs or of providing alternate interconnection to NIAGARA's transmission
system. Such alternative interconnection may be the purchase by SELLER of
NIAGARA's existing 115 kV facilities at depreciated book cost or salvage value,
whichever is lower, but not less than zero. In the event SELLER elects to pay to
NIAGARA the annual charges associated with these facilities, said charges shall
be recomputed as of January 1 of every year.
ELEVENTH: This AGREEMENT shall be effective as of the Effective Date
and shall expire at 11:59:59 P.M. on June 30, 2008.
TWELFTH: ELECTRICITY delivered by SELLER hereunder shall be measured
by electric watthour meters of a type approved by the COMMISSION. The existing
meters located in SELLER's Interconnection Facility (as defined in the Phase I
Interconnection Agreement) satisfy the requirements of this Paragraph TWELFTH.
These metering facilities have been installed, and are owned by SELLER and
maintained by NIAGARA in accordance with the Phase I Interconnection Agreement,
and shall be sealed by NIAGARA, with the seal broken only upon occasion when the
meters are to be inspected, tested or adjusted and representatives of both
NIAGARA and SELLER are present. The meter and installation costs shall be borne
by SELLER. The meters shall be maintained in accordance with the rules set forth
in 16 NYCRR Part 92 which are incorporated herein by reference. In the event
that any meter is found to be inaccurate after the initial year, NIAGARA will
repair or replace the same as soon as possible at the expense of SELLER. Each
Party
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shall have the right at all reasonable times, upon giving not less than five (5)
days notice to the other Party for the purpose of permitting the other Party to
be present at the inspection, to inspect, and test said meters and, if found
defective, NIAGARA shall adjust, repair or replace the same at the expense of
SELLER. Any test or inspection requested by a Party shall be at the expense of
that Party. SELLER shall have the right but not the obligation, to read all
meters installed and maintained pursuant to the Paragraph. Upon written request,
NIAGARA shall provide SELLER's operating personnel with appropriate instructions
and training to enable such personnel to read the meters.
If a meter fails to register, or if the measurement made by a meter is
found to be inaccurate by more than the limits defined in 16 NYCRR Part 92, then
an adjustment shall be made correcting all measurements made by the inaccurate
or defective meter for a) the actual period during which inaccurate measurements
were made, if that period can be determined to the satisfaction of the Parties;
or b) if the actual period cannot be determined to the mutual satisfaction of
the Parties, one-half of the period from the date of the last previous test of
the meter. To the extent that the adjustment period covers a period of
deliveries for which payment has already been made, a payment corresponding to
the adjustment for that period shall be made by the Party against whom the
adjustment runs, to the other Party, not later than the twenty-fifth (25) day of
the month following the month in which the paying Party receives notice from the
other Party that such a payment is due. SELLER may elect to install its own
metering equipment in addition to NIAGARA's metering
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equipment. Such metering equipment shall meet the requirements of 16 NYCRR Part
92. Should any metering equipment installed by SELLER fail to register during
the term of this AGREEMENT, the Parties shall use NIAGARA's metering equipment,
if installed, to determine the amount of ELECTRICITY delivered to NIAGARA. On a
day or days on which neither NIAGARA's nor SELLER's metering equipment is in
service, the quantity of ELECTRICITY delivered shall be determined in such
manner as the Parties shall agree.
THIRTEENTH: The duly authorized agent or agents of NIAGARA shall, at
all reasonable business hours, upon reasonable notice, have free access to the
premises of SELLER for the purpose of inspecting the records of ELECTRICITY
generated at Phase I and delivered to the electric transmission system of
NIAGARA thereat for purchase by NIAGARA.
FOURTEENTH: During the term of this AGREEMENT, NIAGARA shall have the
right, easement and privilege to construct, operate, repair, maintain, remove
and/or replace such electric transmission lines as it may reasonably require
over and across the premises of SELLER for the purposes of receiving and
transmitting the ELECTRICITY herein provided to be delivered to NIAGARA, subject
to the reasonable approval of SELLER. It shall be reasonable for SELLER to
refuse its approval of any such action by NIAGARA if such action would interfere
with the normal operations of Phase I.
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FIFTEENTH: Each Party hereto respectively assumes full responsibility
in connection with the ELECTRICITY supplied hereunder on its side of the
Delivery Point and for the wires, apparatus, devices and appurtenances used in
connection therewith. Each Party shall indemnify, save harmless and defend the
other against all claims, demands, cost or expense for loss, damage or injury to
person or persons or property in any manner directly or indirectly arising from,
connected with or growing out of the generation, transmission or use of energy
by it on its side of the Delivery Point or for the operation of switching
equipment in connection with said delivery; provided, however, that each Party
shall be liable for all claims of the Party's own employees arising out of any
provision of the Workers' Compensation Law. Each Party shall maintain Workers'
Compensation and Employers' Liability Insurance covering their respective
employees as required by law and SELLER shall carry Liability Insurance
including contractual coverage in the amount of at least $1,000,000 per
occurrence.
SIXTEENTH: (A) Upon notice to NIAGARA, SELLER may assign or transfer
the AGREEMENT in whole or in part, without the consent of NIAGARA, (a) as
collateral security for purposes of securing indebtedness, or (b) to any
approved assignee or transferee (an "Approved Assignee"). An Approved Assignee
shall be (i) any person who (x) (a) acquires Phase I, or (b) has a plant with
technical capability that is equal to or greater than the technical capability
of Phase I, and (y) has (a) a long-term unsecured debt credit rating of no less
than investment grade issued by Moody's Investor's Service ("Moody's") or
Standard & Poor's Corporation ("S&P")
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or the equivalent of such rating from another nationally recognized rating
agency, or (b) a net worth calculated in accordance with generally accepted
accounting principles ("Net Worth"), that is equal to or greater than the Net
Worth of the entity making such assignment or transfer on the date of such
assignment or transfer, provided that evidence of such qualifying Net Worth is
reasonably demonstrated to NIAGARA; or (ii) any Affiliate of SELLER; provided
(x) such Affiliate has a long-term unsecured debt credit rating of no less than
investment grade issued by Moody's or S&P or the equivalent of such rating from
another nationally recognized rating agency, (y) such Affiliate has a Net Worth
that is equal to or greater than the Net Worth of the entity making such
assignment or transfer on the date of such assignment or transfer, or (z) SELLER
unconditionally guarantees, pursuant to a guarantee in form and substance
reasonably satisfactory to NIAGARA, the obligations of such Affiliate in
connection with such assignment or transfer. SELLER may split and assign the
quantities of ELECTRICITY and Intervals to Approved Assignees, each in respect
of a lesser quantity and/or Intervals that the full amounts thereof hereunder,
provided that (a) each such assignment is for 50,000 MWh of ELECTRICITY per year
or any integral multiples thereof and to the extent that the remaining
unassigned balance of the quantity of ELECTRICITY hereunder for any such year is
less than 50,000 MWh, then for such remaining balance, (b) each such assignment
is for a period of at least one year, and (c) the sum of all assigned and
retained quantities of ELECTRICITY and Intervals does not exceed the total
quantities of ELECTRICITY and Intervals hereunder. At the request of SELLER
during the term of the AGREEMENT,
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NIAGARA and SELLER shall use their Reasonable Best Efforts to mutually agree
upon reasonable alternatives to the assignment qualification contained in the
immediately preceding sentence. Except to the extent expressly provided in any
applicable guarantee, upon any such assignment or transfer, SELLER shall be
released and have no further obligations to NIAGARA hereunder with respect to
the assigned or transferred quantities and/or Intervals.
(B) NIAGARA shall not assign its rights and obligations hereunder
except as expressly authorized under this section.
(1) In the event that NIAGARA restructures its corporate structure or
assets, including by creating any new entities that hold significant
assets, whether in connection with the Niagara Restructuring or
otherwise, upon notice to SELLER (or its assignee hereunder) the
AGREEMENT will be assigned to and assumed by the entity or entities
owning all or substantially all of NIAGARA's electric transmission and
distribution assets or, if separated from NIAGARA's electric
transmission assets pursuant to such a restructuring (i) such
assignee's performance under this AGREEMENT is unconditionally
guaranteed, pursuant to a guarantee in form and substance reasonably
satisfactory to SELLER (or its assignee hereunder), by each of the
other entities arising out of the restructuring, including any entity
spun-off to NIAGARA's shareholders or any Affiliate of NIAGARA holding
significant assets that were held by NIAGARA prior (or any
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subsidiary of NIAGARA) to the restructuring, unless such assignee has
a long-term unsecured debt credit rating issued by Moody's, S&P or
another nationally recognized rating agency that is at least as
favorable as NIAGARA's long-term unsecured debt credit rating
immediately prior to the effective date of the restructuring, and (ii)
if such assignee is not the entity which will collect from customers
the Competitive Transition Charge approved by the COMMISSION pursuant
to the Commission Approval, such assignee's performance under this
AGREEMENT is unconditionally guaranteed, pursuant to a guarantee in
form and substance reasonably satisfactory to SELLER (or its assignee
hereunder), by each of the entities which will collect from customers
the Competitive Transition Charge provided by the COMMISSION pursuant
to the Commission Approval.
(2) Upon notice to SELLER (or its assignee hereunder), NIAGARA may
assign its rights and obligations under this AGREEMENT to any third
party ("NIAGARA Assignee") (except those parties referenced in
paragraph (1) above) provided that the NIAGARA Assignee has (i)
received a long-term unsecured debt credit rating by Moody's or S&P of
at least investment grade or the equivalent of such rating from
another nationally recognized rating agency, as of the date of
consummation of the assignment; or (ii) furnished SELLER with such
collateral security as may
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be reasonably accepted to SELLER in order to limit SELLER's credit
risk in connection with such assignment.
(C) NIAGARA acknowledges and agrees that (1) based on SELLER's
representations, SELLER is a Delaware limited partnership;(2) NIAGARA's sole
recourse against SELLER shall be to the assets of the limited partnership,
irrespective of any failure to comply with applicable law or any provisions of
this AGREEMENT, except that the partners in SELLER may be joined as nominal
parties for the purpose of enforcing NIAGARA's rights hereunder; (3) no claim
shall be made against any partner in SELLER in connection with this AGREEMENT;
(4) NIAGARA shall have no right to any claim against SELLER for any capital
contributions from any partner in SELLER not yet due and owing; and (5) this
representation is made expressly for the benefit of SELLER and the other
partners in SELLER.
(D) In the event that NIAGARA restructures its corporate structure or
assets, including by creating any new entities that hold significant assets,
whether in connection with the Niagara Restructuring or otherwise, SELLER (or
its assignee hereunder) shall have the right to replace the AGREEMENT, as
applicable, with power purchase and/or hedging contractual arrangements
substantially equivalent to those that are entered into between the entity(ies)
holding the transmission and/or distribution assets of NIAGARA or which will
collect from customers the Competitive Transition Charge approved by the
COMMISSION pursuant to the Commission Approval and the entity(ies) holding the
non-nuclear generating assets
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of NIAGARA, whether or not such assets are spun-off to NIAGARA's shareholders (a
"Genco Contract"), provided that the term, price and quantity under the
AGREEMENT shall not be altered thereby, unless any of such terms are materially
and expressly conditioned by certain provisions in the Genco Contract, in which
case appropriate and equitable adjustments in such terms shall be mutually
agreed upon by NIAGARA or its assignee, as the case may be, and SELLER.
SEVENTEENTH: This AGREEMENT and all of its terms and conditions
shall bind and enure to the benefit of the heirs, executors, administrators,
successors, grantees and assigns of the respective Parties hereto. This
AGREEMENT shall be governed by the substantive laws of the State of New York,
irrespective of conflict of law rules.
EIGHTEENTH: This AGREEMENT is exclusive and contains all of the
terms of the agreement between the Parties and no change or variation in this
AGREEMENT may be made except in express terms and by an instrument in writing
signed by the Parties hereto. Except as expressly included in this AGREEMENT, no
term of the Original Agreement, including any term of any amendment thereto,
shall survive the Effective Date.
NINETEENTH: In the event of any dispute under this AGREEMENT
(other than a payment dispute), either Party may make application to an
appropriate administrative or judicial authority or body for relief. Payment
disputes shall be resolved in accordance with Paragraph NINTH.
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TWENTIETH: Each Party to this AGREEMENT acknowledges that the
COMMISSION had ordered NIAGARA to submit the Original Agreement to the
COMMISSION for its review and possible modification or abrogation within sixty
(60) days of submittal. If either Party objects to any modification to the
Original Agreement by the COMMISSION, it may terminate this AGREEMENT upon
written notice within thirty (30) days from the date the COMMISSION orders such
modification without any liability to the other Party. In the event the
COMMISSION conditions its initial approval of the Original Agreement to provide
for less than full recovery by NIAGARA, through its Fuel Adjustment Clause, of
any payments made by NIAGARA to SELLER under the terms of the Original
Agreement, then this AGREEMENT shall without further notice become null and void
without further liability by either Party to the other. Each Party to this
AGREEMENT acknowledges and agrees that NIAGARA intends to request that the
COMMISSION, in its review of the Original Agreement, expressly find that
NIAGARA's actions, in concluding the pricing provisions of the Original
Agreement, are acceptable to the COMMISSION and each Party to this AGREEMENT
understands and agrees that if the COMMISSION does not so find, this shape
AGREEMENT is null, void and of no effect. NIAGARA agrees to issue a letter to
SELLER, after COMMISSION review and action satisfactory to NIAGARA, stating that
NIAGARA shall not terminate this AGREEMENT pursuant to this Paragraph TWENTIETH.
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TWENTY FIRST: All written notifications pursuant to this AGREEMENT
shall be in writing and shall be personally delivered or mailed by certified or
registered first class mail, return receipt requested, as follows:
TO NIAGARA: To SELLER
SELKIRK Cogen Partners L.P.
NIAGARA MOHAWK POWER CORPORATION 24 Power Park Drive
Director Energy Transactions Selkirk, New York 12158
300 Erie Boulevard West Attn: General Manager
Syracuse, New York 13202 518-475-5773 (phone)
315-428-3159(phone) 518-475-5199 (fax)
315-460-2660(fax)
with a copy to:
Selkirk Cogen Partners, L.P.
c/o US Generating Company
One Bowdoin Square
Boston, Massachusetts 02114
Attn: Legal Group
617-227-8080 (phone)
617-227-2690 (fax)
Either Party may change its address for notices by notice to the other
in the manner provided above.
TWENTY-SECOND: In the event either Party hereto is rendered unable,
wholly or in part, by Force Majeure to carry out its obligations under the
AGREEMENT, other than the obligation to make payments of amounts due hereunder,
it is agreed that upon notice, with reasonably full particulars of such Force
Majeure given by such Party to the other Party in writing within a reasonable
time frame after the occurrence of the cause relied upon, then the obligation or
obligations
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hereunder of the Party giving such notice, so far as they are affected by such
Force Majeure, shall be suspended during the continuance of an inability so
caused. Such cause shall, as far as possible, be remedied with all reasonable
dispatch.
TWENTY THIRD: SELLER shall have the right to have NIAGARA wheel some
or all of the output of Phase I to third parties pursuant to applicable law, or
NIAGARA's, or other companies', duly filed transmission and distribution tariffs
or schedules.
SELLER may, at its option but subject to NIAGARA's right of first
refusal under this AGREEMENT, elect firm and interruptible transmission service
under the Transmission Agreement for delivery of electricity from Phase I to
Consolidated Edison Company of New York, Inc. ("Con Edison"); provided that
NIAGARA shall have no obligation to transmit energy on a firm basis under the
Transmission Agreement in excess of the Contract Demand (as set forth in the
Transmission Agreement), inclusive of amounts transmitted under the Transmission
Agreement with respect to Phase II. SELLER may, at its option but subject to
NIAGARA's right of first refusal under this AGREEMENT, elect interruptible
transmission service under the Transmission Agreement for delivery of
electricity from Phase I to any third party in addition to Con Edison; provided
that NIAGARA shall have no obligation to transmit energy on an interruptible
basis under the Transmission Agreement in excess of the amounts permitted
pursuant to Schedule E of the Transmission Agreement. The rights and obligations
under this paragraph are in addition to any rights or
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obligations which the Parties may have pursuant to Paragraph TWELFTH of this
AGREEMENT or under the Transmission Agreement.
TWENTY-FOURTH: No failure on the part of a Party to exercise, and no
delay in exercising, any right hereunder shall operate as a waiver thereof. No
waiver by a Party of any right hereunder with respect to any matter or default
arising in connection with this AGREEMENT shall be considered a waiver with
respect to any subsequent matter or default.
TWENTY-FIFTH: This AGREEMENT may be executed by the Parties in
separate counterparts, each of which shall be deemed to be an original, and all
such counterparts shall together constitute but one and the same instrument.
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IN WITNESS WHEREOF, the Parties hereto have caused this Amended and
Restated Agreement to be executed as of the day and year first above written.
Selkirk Cogen Partners, L.P.
By: JMC Selkirk, Inc., Managing
General Partner
By: /s/George J. Grunbeck
--------------------------------
Title: Vice President
Date: 8/10/98
NIAGARA MOHAWK POWER CORPORATION
By: /s/ Clement E. Nadeau
--------------------------------
Title: Vice President-Marketing and
Planning
Date: 8/11/98
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SCHEDULE A
Definitions
As used in this AGREEMENT:
"AGREEMENT" means this Amended and Restated Agreement dated as of July
1, 1998, by and between SELLER and NIAGARA and the schedules and attachments
thereto.
"Affiliate" means, with respect to any Party to this AGREEMENT, any
person or entity which controls, is controlled by, or is under the common
control with, such Party, wherein the term "control" shall mean the power to
direct the management and policies by or of such Party through the ownership of
voting securities, by contract or otherwise.
"Business Day" shall mean any day other than a Saturday, Sunday or
other day on which banks in the State of New York are authorized or required to
be closed.
"Call Energy Price" shall have the meaning set forth in Section (B)(3)
of Paragraph SEVENTH of the Agreement.
"Call Gas Price" shall have the meaning set forth in Section II of
ATTACHMENT I.
"Call Option Quantity" shall have the meaning set forth in Section
(B)(1) of Paragraph SEVENTH.
"COMMISSION" means the Public Service Commission of the State of New
York.
"Commission Approval" means a final COMMISSION order setting forth the
findings, authorizations and approvals set forth in Schedule 6.6C of the Master
Restructuring Agreement.
"Competitive Transition Charge" means a charge, however designated, for
the recovery of strandable costs.
"Contract Year" means the period commencing on the Effective Date and
ending at 11:59:59 p.m. on the first anniversary of the last day of the month in
which the Effective Date occurs and each successive 12-month period thereafter
to the extent applicable.
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"Delivered Call Quantity" means the Call Option Quantity and Excess
Energy SELLER sells, and tenders for delivery at the Delivery Point, to NIAGARA
pursuant to Section (B) of Paragraph SEVENTH for each Interval during the
Settlement Period, and NIAGARA shall be obligated to take and pay for such
ELECTRICITY and Excess Energy at the Call Energy Price.
"Delivered Capacity Quantity" means the amount of capacity SELLER
sells to NIAGARA pursuant to Sections (A) and (C) of Paragraph SEVENTH of the
AGREEMENT, which is subject to both seasonal variation and degradation,
associated with and up to the specified Monthly Contract Quantity, for each
Interval during the Settlement Period, and NIAGARA shall be obligated to take
and pay for such capacity from SELLER at the Market Capacity Price.
"Delivered Energy Quantity" means the amount of energy SELLER sells,
and tenders for delivery at the Delivery Point, to NIAGARA pursuant to Sections
(A) and (C) of Paragraph SEVENTH of the AGREEMENT up to the specified Monthly
Contract Quantity plus the Overgeneration Amount, for each Interval during the
Settlement Period, and NIAGARA shall be obligated to take and pay for such
energy from SELLER at the Market Energy Price.
"Delivery Point" means (a) with respect to ELECTRICITY delivered from
Phase I, the Receiving Point as set forth in the Phase I Interconnection
Agreement; (b) with respect to any ELECTRICITY delivered from Phase II, the
Receiving Point as set forth in the Phase II Interconnection Agreement; and (c)
with respect to ELECTRICITY delivered hereunder from any other source, any other
interconnection on NIAGARA's transmission system, subject to NIAGARA's
concurrence which shall not be unreasonably withheld.
"Effective DMNC" shall have the meaning set forth in Section VI(c) of
Attachment I.
"Effective Date" means 11:59:59 p.m. on June 30, 1998.
"ELECTRICITY" means the capacity and/or energy produced by Phase I or
otherwise sold by SELLER in accordance with the terms of this AGREEMENT.
"ESB #756" means NIAGARA's Electric System Bulletin #756 dated
December 1997 (including Appendix C but excluding any provisions related to
coordinated maintenance), as amended, supplemented or modified from time to
time, provided that no amendment, supplement or modification shall be effective
with respect to SELLER sooner than sixty days after receipt by SELLER of the
effective version and NIAGARA agrees to provide notice of any planned amendment,
supplement or modification and drafts thereof as far in advance of effectiveness
as is reasonably possible and NIAGARA shall give due consideration of any
comments of
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SELLER thereto with respect to Phase I.
"Force Majeure" as used herein means acts of God, strikes, lockouts,
act of public enemies, wars, blockades, insurrections, riots, epidemics,
landslides, lightning, system emergencies, earthquakes, fires, storms, floods,
washouts, arrests, explosions, breakage or accident to machinery, equipment or
transmission or distribution lines; provided that the term Force Majeure does
not mean or include any cause which by the exercise of reasonable diligence of
the Party claiming suspension could be overcome.
"Gas IPPs" means those IPPs which produce power using primarily
natural gas.
"Governmental Authority" means any federal, state, municipal or local
governmental authority, department, commission, board, agency, body or official,
whether executive, legislative, administrative, regulatory or judicial,
including but not limited to the FERC and the COMMISSION.
"Interval" means (i) 1 hour; provided that, in the event that
following the Proxy-Market Price Period, ISO/PE procedures require the use of an
alternate time period, such alternate time period shall automatically be deemed
to be incorporated in, and shall supersede, the 1 hour period set forth herein,
or (ii) such time period as NIAGARA and SELLER shall mutually agree in writing;
provided that such mutually agreed upon time period may only be subsequently
modified upon the prior written consent of NIAGARA and SELLER.
"IPP(s)" means those independent power producers that are identified
on the signature pages and on Schedule A of the Master Restructuring Agreement.
"ISO/PE" means a New York Independent System Operator and Power
Exchange.
"LBMP" shall have the meaning ascribed to it in the definition of
Market Energy Price.
"Market Capacity Price" shall equal zero prior to the establishment of
the ISO/PE and thereafter at any time when no separate market for capacity
exists. Commencing on the first day of the month following the calendar month in
which the ISO/PE is established and only if there then exists a separate market
for capacity, the Market Capacity Price shall mean the market price paid to
sellers for capacity, at the Delivery Point or the region in which the Delivery
Point is located, established by the ISO/PE capacity auction; provided, however,
that at such time the Parties shall conduct good faith negotiations and use
their Reasonable Best Efforts to mutually
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determine whether to continue the pricing referred to in clause (i) of the
definition of Market Energy Price for a mutually agreed upon additional period
of time.
"Market Energy Price" means for any Interval (i) prior to and until
the establishment of the ISO/PE and the implementation of LBMP pricing hereunder
(as defined below), NIAGARA's short-term avoided energy and capacity at the
voltage level of the Delivery Point, as stated in its tariff approved by the
COMMISSION providing for the purchase of power from PURPA qualifying facilities,
which tariff is currently designated as S.C.-6, as the same may be in effect
from time to time or any successor tariff thereto (the "S.C.-6 Rate") or such
other price as may be agreed upon by NIAGARA and SELLER during individual
negotiations, and (ii) on the first day of the month following the calendar
month in which the ISO/PE is established and implementing day ahead locational
based market pricing ("LBMP"), the LBMP paid to sellers for energy, at the
Delivery Point or the region in which the Delivery Point is located, specified
and published by the ISO/PE; provided, however, that at such time SELLER and
NIAGARA shall conduct good faith negotiations and use their Reasonable Best
Efforts to mutually determine whether to continue the pricing referenced in
clause (i) above for a mutually agreed upon additional period of time. The
Market Energy Price shall not be reduced or offset by any costs that NIAGARA may
incur, including, without limitation, costs for ancillary services, transmission
services or transition (stranded) costs.
"Master Restructuring Agreement" means the Agreement dated July 9,
1997, as amended, by and between NIAGARA, the SELLER and several other
independent power producers identified therein.
"Monthly Contract Quantity" means the amount of electricity (expressed
in MWh/hr) as set forth in ATTACHMENT I-A under the heading Monthly Contract
Quantity for the applicable month, and which may be adjusted in accordance with
the terms of ATTACHMENT I-A.
"Niagara Restructuring" means NIAGARA's proposed corporate
restructuring and disaggregation in connection with the PowerChoice proposal.
"Notice" means a notice of payments due pursuant to Paragraph NINTH
delivered by SELLER to NIAGARA.
"Notional Quantity" means the amount of capacity (expressed in MW) as
set forth in ATTACHMENT I-A under the heading Notional Quantity for the
applicable Contract Year.
"NYPSL" means the New York Public Service Law.
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"Original Agreement" shall have the meaning set forth in the first
WHEREAS clause.
"Overgeneration Amount" means an amount of energy in excess of the
Monthly Contract Quantity of electricity set forth in ATTACHMENT I-A; provided
such amount of excess energy shall not exceed 5% of the Monthly Contract
Quantity of electricity for the applicable Interval. SELLER shall have the right
to put the Overgeneration Amount to NIAGARA hereunder at the Market Energy Price
or the Call Energy Price, as applicable.
"Party" means the SELLER or NIAGARA.
"Parties" means the SELLER and NIAGARA.
"Payment Date" means the day of the month which is the later of (i)
the 25th day of the month in which a Notice is given by SELLER to NIAGARA; or
(ii) the 15th day after the delivery by SELLER to NIAGARA of a Notice. In the
event that such 25th or 15th day is not a Business Day, the corresponding
payment shall be due on or before the first Business Day following such 25th or
15th day or legal holiday, as the case may be.
"Phase I" means the first unit of the PLANT which commenced commercial
operation on April 17, 1992.
"Phase II" means the second unit of the PLANT which commenced
operation on September 1, 1994.
"Phase I Interconnection Agreement" means the Interconnection
Agreement, dated October 20, 1992, between NIAGARA and SELLER with respect to
Phase I.
"Phase II Interconnection Agreement" means the Interconnection
Agreement, dated October 20, 1992, between NIAGARA and SELLER with respect to
Phase II.
"PLANT" means SELLER's two unit electric generating facility located
in Selkirk, New York.
"Proxy-Market Price Period" means the period commencing on the
Effective Date and ending on the first day of the calendar month following the
calendar month in which the ISO/PE has been fully established and functioning,
provided the following conditions have been satisfied during each of the
previous six months: (i) the volumes (in GWh) of energy sales and purchases
transacted through the ISO/PE in the day ahead market based upon the day ahead
pricing mechanism adopted by the
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FERC for the ISO/PE for the Upstate Market shall be at least equal to those
corresponding with the months listed in the following table (which GWh shall
include the aggregate contract quantities of energy during such period under all
physical delivery Restated Contracts with Gas IPPs, regardless of whether the
IPPs parties thereto actually effected such sales, and all sales on up to a
monthly basis of energy (other than sales through the ISO/PE) by the IPPs
parties to the Master Restructuring Agreement which are effectuated by NIAGARA
acting as agent for any such IPP);
Month GWh
January 4,611
February 4,136
March 4,327
April 3,827
May 3,788
June 3,974
July 4,278
August 4,160
September 3,793
October 3,856
November 3,896
December 4,361
and (ii) only if a separate market for capacity then exists, a minimum of 5,700
MW of the capacity sales and purchases within the Upstate Market have been
transacted through the ISO/PE capacity auction (which MW shall include the
aggregate capacity associated with the aggregate contract quantities of energy
during such period under all physical delivery Restated Contracts with Gas IPPs,
regardless of whether the IPPs parties thereto actually effected such sales, and
all sales on up to a monthly basis of capacity (other than sales through the
ISO/PE) by the IPPs parties to the Master Restructuring Agreement which are
effectuated by NIAGARA acting as agent for any such IPP). Notwithstanding the
foregoing, the Proxy-Market Price Period may be extended or terminated upon the
mutual agreement of the parties.
In the event the ISO/PE does not provide adequate information to confirm the
monthly sales within the Upstate Market transacted through the ISO/PE, NIAGARA
and SELLER agree to renegotiate the conditions based on the original intent of
the Master Restructuring Agreement (as defined by the "Proxy-Market Price
Period", page 28, Attachment A-8 of the "Terms and Conditions of Amended PPA and
Restated Contracts".
"PUHCA" shall mean the Public Utility Holding Company Act of 1935, as
amended.
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"PURPA" shall mean the Public Utility Regulatory Policies Act of 1978,
as amended.
"Reasonable Best Efforts" means, with respect to any Party, such
Party's diligent pursuance of the course of action or result stated as
determined by such Party itself in good faith, but shall not require such Party
to pay any sum or other consideration or incur or assume any liability or
obligation that is not otherwise expressly required to be paid, incurred or
assumed pursuant to this AGREEMENT, excluding (i) normal and customary
incidental out-of-pocket costs and expenses and (ii) attorneys' fees (except,
with respect to any IPP, attorneys' fees required to be paid by NIAGARA pursuant
to the IPPs' Special Counsel Fee Letter or the IPPs' Local Regulatory Counsel
Fee Letter).
"Restated Contracts" has the meaning set forth in Exhibit A to the
Master Restructuring Agreement.
"S.C.-6 Rate" shall have the meaning ascribed to it in the definition
of Market Energy Price.
"S.C.-6 Price Period" means the period commencing on the Effective
Date and expiring on the earlier to occur of (a) the first day of the month
following the calendar month in which the ISO/PE is established and implementing
LBMP pricing and (b) twenty four (24) months after the Effective Date.
"Settlement Date" means the last day of each calendar month during the
term of this AGREEMENT commencing on the Effective Date.
"Settlement Period" means each calendar month during the term of this
AGREEMENT.
"Transmission Agreement" means the Transmission Services Agreement,
dated as of December 13, 1990, as amended, between NIAGARA and SELLER.
"Upstate Market" means collectively (i) the service territory retail
loads in the regions currently served by Niagara Mohawk Power Corporation, New
York State Electric & Gas Corporation, Rochester Gas & Electric Corporation and
Central Hudson Gas & Electric Corporation (each a "Utility", collectively the
"Utilities"), and (ii) wholesale sales transactions by any of the Utilities to
third parties outside the regions currently served by such Utility, excluding
any such sales which are effectuated pursuant to contracts having a term of at
least one year existing as of the date of the Master Restructuring Agreement to
the extent such contracts are in effect thereafter.
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"Variable Energy Cost" shall have the meaning set forth in Section II
of ATTACHMENT I.
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MUTUAL GENERAL RELEASE AND AGREEMENT
THIS MUTUAL GENERAL RELEASE AND AGREEMENT ("Release") dated as of July
1, 1998, by and between NIAGARA MOHAWK POWER CORPORATION, a New York corporation
("NMPC"), and SELKIRK COGEN PARTNERS, L.P., a Delaware limited partnership
("Selkirk"). Capitalized terms used herein and not otherwise defined herein
shall have the meanings ascribed to such terms in the Master Restructuring
Agreement (as hereinafter defined). (Selkirk and NMPC are collectively referred
to herein as the "Parties" and individually referred to as a "Party.")
RECITALS
(A) NMPC and Selkirk are parties to, among other agreements, a certain
power purchase agreement described on Schedule 1 hereto (referred to herein as
the "Existing PPA") pursuant to which NMPC purchases power produced by Selkirk's
approximately 79.9 MW co-generation facility located in Selkirk, New York (the
"Project"); and
(B) NMPC and Selkirk, among others, have entered into a certain Master
Restructuring Agreement, dated as of July 9, 1997, as amended (the "Master
Restructuring Agreement" or "MRA"), pursuant to Sections 8.8 and 9.8 of which
NMPC and the Selkirk have agreed to execute and deliver this Release; and
(C) NMPC and Selkirk have modified the terms of the Existing PPA by
entering into an Amended and Restated Agreement dated as of July 1, 1998
("Restated Contract") in accordance with Section 3.2 of the MRA, effective as of
the Effective Time (subject to Selkirk's right to delay the effectiveness of the
Restructuring with respect to it pursuant to Section 8.15 of the MRA) (the
Effective Time as it may be extended with respect to Selkirk, the "Selkirk
Effective Time").
NOW, THEREFORE, in consideration of the foregoing premises and for
other good and valuable consideration, the receipt and adequacy of which is
hereby acknowledged, the Parties hereby agree as follows, in each case effective
as of the Selkirk Effective Time:
1. Release by the Parties. NMPC and Selkirk hereby agree that
effective as of Selkirk Effective Time, without any further notice or action on
the part of NMPC or Selkirk and except as set forth in Section 2 hereof, (a) the
Existing PPA shall be irrevocably amended and restated by the Restated
Agreement; (b) all rights and privileges granted, accruing or inuring to each
Party pursuant to the Existing PPA shall be irrevocably superseded by the
Restated Agreement; (c) all obligations and duties owed or required by the
Existing PPA to be performed for or on behalf of one Party by any other Party
thereto shall be irrevocably waived and released; and (d) each Party to the
Existing PPA and its respective predecessors and successors in interest, agents,
directors, officers, partners, trustees, employees and affiliates, shall be
irrevocably released and forever discharged from
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all manner of actions, causes of action, suits, debts, sums of money, accounts,
reckonings, bonds, bills, covenants, contracts, controversies, agreements,
judgments claims and demands whatsoever, in law or equity, known or unknown,
which any other Party ever had, now has or hereafter can, shall or may have,
based upon or by reason of any matter, cause or thing related to or arising out
of the Existing PPA. NMPC hereby acknowledges and agrees that the Consent and
Agreement, dated as of October 23, 1992 (the "Consent"), among NMPC, Selkirk and
the bank party thereto, as confirmed by the Confirmation Agreement, effective
May 9, 1994 (the "Confirmation"), among NMPC, Selkirk and the entities thereto,
shall continue in effect with respect to the Restated Agreement and NMPC shall
execute and deliver such further documentation as Selkirk may reasonably request
evidencing the foregoing in connection with the effectiveness of the
Restructuring for Selkirk. NMPC hereby consents to the assignment of those
provisions of the MRA which by the terms of the MRA survive the Consummation
Date until fully performed (the "MRA Surviving Provisions") and this Release by
Selkirk to Banker's Trust Company, as Collateral Agent, as security under
Selkirk's financing agreements and agrees, for the benefit of the Collateral
Agent and for the purposes of the Consent and the Confirmation, that each of the
MRA Surviving Provisions and this Release shall be deemed to be an Assigned
Agreement (as defined in the Consent and the Confirmation). Selkirk hereby
represents and warrants to NMPC that, upon Selkirk's delivery of notice to NMPC
that the Indenture Approval has been obtained, the amendment and restatement of
the Existing PPA by the Restated PPA and the termination of the License
Agreement, dated October 23, 1992, between Selkirk and NMPC will not be in
conflict with and will not constitute, with or without the passage of time or
giving of notice, or both, a default under Selkirk's Trust Indenture and the
other financing agreements related thereto.
2. Certain Claims Not Released. Nothing contained herein shall
constitute a waiver or release of any claims, liabilities or obligations (i)
arising out of or in connection with this Release, (ii) arising out of or in
connection with any litigation or regulatory proceedings which are not to be
dismissed and withdrawn (or effectively withdrawn) by NMPC or Selkirk pursuant
to Sections 8.8(b) and 9.8(b) of the MRA, (iii) unless dismissed or withdrawn
pursuant to the Section 8.8(b) or 9.8(b) of the MRA, arising out of or in
connection with any payment due to Selkirk whether or not disputed, for any
power or services purchased by NMPC, or any payment due to NMPC whether or not
disputed, for any services provided by NMPC, pursuant to the Existing PPA,
provided that if such payment relates to any period prior to May 10, 1997,
Selkirk's or NMPC's, as the case may be, entitlement to such payment shall have
been set forth in a writing given to NMPC or Selkirk, as the case may be, on or
before June 15, 1997 and (iv) arising pursuant to Section 8.15 and Section
12.4(d) or any other provision of the MRA which by the terms of the MRA survive
the Consummation Date until fully performed. NMPC and Selkirk acknowledge and
agree that in accordance with Section 1 hereof all claims, liabilities and
obligations relating to tracking, adjustment or advance payment account
provisions under the Existing PPA (including without limitation the Adjustment
Account, the Tax Carrying Charge Account or the Performance Account (as each
such term is defined in the Existing PPA)) shall be extinguished as of the
Selkirk Effective Time, any and all letters of credit provided by Selkirk in
connection with the Existing PPA shall be returned to Selkirk on the
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Selkirk Effective Time, and the License Agreement, dated as of October 23, 1992,
entered into by Selkirk and NMPC in accordance with the Existing PPA shall be
deemed terminated as of the Selkirk Effective Time.
3. Reconciliation of Certain Amounts. Pursuant to Section 8.15 of the
MRA, the Parties shall use the methodology set forth in Schedule 2, to
simultaneously reconcile between them in cash on and as of the Selkirk Effective
Time any payments made pursuant to the Existing PPA which are in excess of or
less than payments that would have been made pursuant to the Restated Contract
had such Restated Contract been in effect from July 1, 1998 until the Selkirk
Effective Time.
4. Amendments. This Release may not be amended except by an instrument
in writing and signed by the Party against whom such amendment is sought to be
enforced.
5. Successors and Assigns. The terms and conditions of this Release
shall inure to the benefit of and be binding upon the respective successors and
assigns of the Parties hereto.
6. Governing Law. This Release, including the validity hereof and the
rights and obligations of the Parties hereunder, and all amendments and
supplements hereof and all waivers and consents hereunder, shall be construed in
accordance with and governed by the domestic substantive laws of the State of
New York without giving effect to any choice of law or conflicts of law
provision or rule that would cause the application of the domestic substantive
laws of any other jurisdiction.
7. Severability. If any provisions of this Release as applied to any
part or to any circumstance shall be adjudged by a court to be invalid or
unenforceable, the same shall in no way affect any other provision of this
Release, the application of such provision in any other circumstances or the
validity or enforceability of this Release.
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IN WITNESS WHEREOF, the Parties hereto have entered into this Mutual
General Release and Agreement as of the date first above written.
NIAGARA MOHAWK POWER CORPORATION
By: /s/Clement E. Nadeau
---------------------------
Its: Vice President
SELKIRK COGEN PARTNERS, L.P.
By: JMC Selkirk, Inc., managing general partner
By: /s/George J. Grunbeck
---------------------------
Its: Vice President
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SECOND AMENDED AND RESTATED
GAS PURCHASE CONTRACT
BETWEEN
PARAMOUNT RESOURCES LTD.
AND
SELKIRK COGEN PARTNERS, L.P.
Dated as of May 6, 1998
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TABLE OF CONTENTS
ARTICLE 1. DEFINITION OF TERMS.......................................3
ARTICLE 2. CONTRACT QUANTITIES; DELIVERIES..........................10
ARTICLE 3. DELIVERY POINT...........................................12
ARTICLE 4. DELIVERY PRESSURE........................................12
ARTICLE 5. COMMENCEMENT OF SALES AND DELIVERIES.....................12
ARTICLE 6. TERM OF CONTRACT.........................................13
ARTICLE 7. PRICE....................................................16
ARTICLE 8. BILLINGS AND PAYMENTS....................................20
ARTICLE 9. QUALITY..................................................22
ARTICLE 10. MEASUREMENT OF GAS.......................................23
ARTICLE 11. POSSESSION AND TITLE.....................................23
ARTICLE 12. SELLER'S REPRESENTATIONS AND WARRANTIES..................23
ARTICLE 13. SELLER'S RESERVATIONS....................................26
ARTICLE 14. ASSURANCES OF GAS SUPPLY; SUBSTITUTE GAS SUPPLY..........29
ARTICLE 15. LIABILITIES AND LIMITATION OF LIABILITIES................42
ARTICLE 16. FORCE MAJEURE............................................44
ARTICLE 17. LAWS AND REGULATORY BODIES...............................46
ARTICLE 18. TRANSFER AND ASSIGNMENT..................................46
ARTICLE 19. MISCELLANEOUS PROVISIONS.................................47
ARTICLE 20. ARBITRATION..............................................50
ARTICLE 21. NONRECOURSE OBLIGATION OF JOINT VENTURE..................51
ARTICLE 22. MATERIAL BREACH; REMEDIES................................52
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LIST OF EXHIBITS
Exhibit A - Summary of Lands to be Dedicated with Reserve Summaries
Exhibit B - Guarantee
Exhibit C - Indemnity
Exhibit D - Letter of Credit
Exhibit E - Form of New Contract
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SECOND AMENDED AND RESTATED GAS PURCHASE CONTRACT
This Second Amended and Restated Gas Purchase Contract is dated the
6th day of May, 1998, by and between Paramount Resources Ltd., a Canadian
corporation, herein called the "Seller," and Selkirk Cogen Partners, L.P., a
Delaware limited partnership, herein called the "Buyer," pursuant to the
following recitals and representations:
W I T N E S S E T H
WHEREAS, Seller is engaged in the production of gas in Canada and the
marketing of such gas to others; and
WHEREAS, Buyer is a limited partnership engaged in the generation and
sale of electricity from an electric generating facility located in Selkirk, New
York and will enter into an Amended and Restated Power Sale Agreement with
Niagara Mohawk Power Corporation, effective on or before the Effective Date (as
defined below), and also sells steam to the General Electric Company's plastics
facility in Selkirk, New York; and
WHEREAS, Seller and Buyer require approvals from the United States and
the Canadian regulatory and governmental authorities for the sale and purchase
of gas to operate Buyer's Plant on the terms provided herein; and
WHEREAS, Seller has entered into a gas transportation service contract
with NOVA Corporation of Alberta ("NOVA") for firm transportation pursuant to
which NOVA has agreed to transport such quantities of gas sold by Seller to
Buyer under this Gas Purchase Contract from production receipt points within the
Province of Alberta to a point near Empress, Alberta; and
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WHEREAS, Buyer has entered into a transportation contract with
TransCanada PipeLines Limited ("TCPL") pursuant to which TCPL has agreed to
receive from NOVA for Buyer's account such quantities of gas sold by Seller to
Buyer under this Gas Purchase Contract at a point near Empress, Alberta where
its facilities interconnect with the facilities of NOVA and to transport such
gas from such point to a point on the International Border between the Province
of Ontario and the State of New York near Iroquois, Ontario; and
WHEREAS, Buyer has entered into transportation contracts with
Tennessee Gas Pipeline Company and Iroquois Gas Transmission System, L.P.,
herein collectively called "United States Transporter," pursuant to which United
States Transporter agrees to receive gas from TCPL for Buyer's account at a
point on the International Border between the Province of Ontario and the State
of New York near Iroquois, Ontario where its facilities will interconnect with
the facilities of TCPL and to transport such gas from such point to Buyer's
Plant; and
WHEREAS, Seller and Buyer have entered into a Gas Purchase Contract as
of the 15th day of December 1989, as amended by a letter agreement dated June 9,
1990, as amended and restated by an Amended and Restated Gas Purchase Contract,
dated as of September 26, 1992, and as further amended prior to the date hereof
(the "Original Gas Purchase Contract"); and
WHEREAS, Seller and Buyer desire to amend and restate the Original Gas
Purchase Contract upon the terms and conditions set forth herein;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements herein contained, Seller and Buyer agree as follows:
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ARTICLE I. DEFINITION OF TERMS
1.1. The term "AEUB" shall mean the Alberta Energy and Utilities Board or any
successor board or agency.
1.2. The term "Buyer's Plant" shall mean Phase I of Buyer's electric
cogeneration facility located in Selkirk, New York, with a net electric
generating capability of approximately 79.9 megawatts.
1.3. The term "British thermal unit" or "Btu" shall mean the amount of heat
required to raise the temperature of one (1) pound of distilled water one (1)
degree Fahrenheit at sixty (60) degrees Fahrenheit at a constant pressure of
14.73 pounds per square inch absolute.
1.4. The term "Canadian Regulatory Authorities" shall mean each governmental
agency or other authority in Canada, which has jurisdiction over the matters in
question, including without limitation the NEB, the AEUB, and the federal
Governor-in-Council and provincial Lieutenant Governor-in-Council, so long as
and to the extent that such agencies and authorities have jurisdiction over the
matters in question.
1.5. The term "Commencement of Firm Deliveries" shall have the meaning set forth
in Section 5.1.
1.6. The term "Contract", shall mean this Second Amended and Restated Gas
Purchase Contract, as amended from time to time, including all exhibits hereto.
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1.7. The term "contract year" with respect to the first "contract year" shall
mean the period commencing on the Commencement of Firm Deliveries and ending at
8:00 a.m. Eastern Standard Time on the following November 1, and with respect to
any succeeding "contract year" shall mean the period of twelve (12) consecutive
months from the end of the preceding contract year to 8:00 a.m. Eastern Standard
Time on the next succeeding November 1.
1.8. The term "cubic foot" shall mean the volume of gas which occupies one cubic
foot when such gas is a temperature of sixty degrees Fahrenheit (60(degree) F)
and at a pressure of 14.73 pounds per square inch absolute.
1.9. The term "cubic metre of gas" or "(m3)" shall mean the quantity of gas
which occupies one cubic metre at a temperature of fifteen degrees Celsius
(15(degree) C) and at an absolute pressure of 101.325 kilopascals.
1.10. The term "Daily Nomination" shall mean the volume of natural gas, up to
the Maximum Daily Quantity, which Buyer requests Seller to cause to be delivered
by NOVA to TCPL at the Delivery Point during any one day for Buyer's account.
1.11. The term "Date Certain" shall mean the first day of each contract year.
1.12. The term "Date of Commercial Operation" shall mean April 17, 1992.
1.13. The term "Date of Firm Transportation" shall be the date upon which
transportation is available to Buyer to enable firm deliveries of the Maximum
Daily Quantity from the Delivery Point to Buyer's Plant.
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1.14. The term "day" shall mean a period of twenty-four consecutive hours,
beginning and ending at 8:00 a.m. Eastern Standard Time.
1.15 The term "Deliverable Gas" shall mean the amount of Seller's Reserves for
any contract year which can be produced for sale and delivered from wells which
are (i) tied-in and (ii) producing or producible with no additional capital
expenditure, in accordance with applicable law, which amount shall be determined
by making due allowance for production losses, uses and treatment shrinkages,
transportation and fuel. All knowledge concerning all reservoirs penetrated by
wells and conditions of wells and facilities existing as of the time of each
Determination shall be taken into consideration.
1.16. The term "Delivery Point" shall mean the point where the facilities of
NOVA and TCPL interconnect near Empress, Alberta or such other point(s) proposed
by Buyer and consented to by Seller, such consent not to be unreasonably
withheld, that Seller can deliver and Buyer can receive gas.
1.17. The term "Delivery Pressure" shall mean a gauge pressure suitable to enter
TCPL's facilities at the Delivery Point.
1.18. The term "Effective Date" shall have the meaning set forth in Section
6.1.a.
1.19. The term "Exhibit `A'" shall mean Exhibit A attached hereto, as said
Exhibit A may be supplemented, or otherwise modified in accordance with the
terms hereof.
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1.20. The term "Excess Third Party Sales" shall mean any sale of gas from
Seller's Lands to a third person which is not a Third Party Sale.
1.21. The term "gas" or "natural gas" shall mean natural gas of the quality
specified in Article 9 hereof.
1.22. The term "GJ" shall mean gigajoules or one billion (1,000,000,000) joules.
1.23. The term "Heating Value" shall mean gross or higher heating value and be
expressed as MJ/M3 and shall equal the number of MJ's produced by the combustion
in a recording calorimeter at a constant pressure of a cubic metre of gas at a
temperature of fifteen degrees Celsius (15(0) C), with the gas free of all water
vapor, and at an absolute pressure of 101.325 kilopascals and with the products
of combustion cooled to the initial temperature of the gas and the water formed
by the combustion condensed to the liquid state.
1.24. The term "Initial Recoverable Reserves" shall mean the quantity of gas
which is the sum of:
1.24.a. The total quantity of gas equal to the product of the Maximum
Daily Quantity multiplied by the number of days in the period commencing on the
Commencement of Firm Deliveries and ending on the first day of the contract year
occurring during the period for which a Determination is made pursuant to
Section 14.2; and
1.24.b. The total remaining quantity of gas recoverable from Seller's
Reserves and available for pipeline transportation as of the first day of the
contract year for which a
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Determination is made pursuant to Section 14.2. In determining such total
quantity, due allowance shall be made for production losses and uses and
treatment shrinkages. All knowledge concerning all reservoirs penetrated by
wells and conditions of wells and facilities existing as of the time of each
Report shall be taken into consideration.
1.25 The term "joule" or "J" shall mean the work done when the point of
application of a force of one (1) newton is displaced a distance of one (1)
metre with direction of force.
1.26. The term "Leases" shall mean all rights, documents and/or titles by virtue
of which the holder thereof is entitled to drill for, produce and sell gas from
Seller's Lands or to cause gas to be drilled for, produced and sold from
Seller's Lands as described in Exhibit "A" attached hereto.
1.27. The term "Mcf" shall mean one thousand (1,000) cubic feet and shall be
equal to 0.02832 l03m3.
1.28. The term "MMBtu" shall mean one million (1,000,000) Btu's.
1.29. The term "MMcf" shall mean one million (1,000,000) cubic feet of gas.
1.30. The term "Maximum Daily Quantity" shall mean a daily volume of gas equal
to 464.5 103m3 (16,400 Mcf) which may be reduced from time to time pursuant to
this Contract.
1.31. The term "Minimum Deliverable Gas Amount" shall mean the Deliverable Gas
for any five consecutive contract years, or such lesser number of contract years
remaining in the unexpired term of this Contract, in an amount not less than (a)
one hundred percent (100%) of the annual
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average of the Maximum Daily Quantity for the first, second and third of such
contract years, (b) ninety percent (90%) of the annual average of the Maximum
Daily Quantity for the fourth of such contract years, and (c) eighty percent
(80%) of the annual average of the Maximum Daily Quantity for the fifth of such
contract years.
1.32. The term "Minimum Removal Permit" shall mean, so long as an AEUB removal
permit is required at law for the removal of gas from the Province of Alberta, a
removal permit issued by the AEUB authorizing the removal of gas from Alberta,
to be used in the performance of this Contract, being (i) the current AEUB
removal permit (GR 91-94F) from the Effective Date through October 31, 2001 and
(ii) as of November 1, 2001 and annually thereafter, a removal permit which at
all times permits the removal of gas as follows: (1) commencing on the November
1, 2001 Date Certain and thereafter on each annual Date Certain for the then
next succeeding full two (2) contract years of twelve (12) months each, or such
lesser number of contract years remaining in the unexpired term of the Contract,
an amount equal to the difference between (a) the product of the Maximum Daily
Quantity and the total number of days in such contract year less (b) NWT
Reserves (i) tied-in and (ii) producing or producible with no additional capital
expenditure; and (2) thereafter, as the AEUB may determine, such that Seller at
all times maintains an AEUB removal permit for the gas to be delivered hereunder
from the Province of Alberta for the then current contract year and the next
succeeding contract year during the term of this Contract.
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1.33. The term "month" shall mean the period beginning at 8:00 a.m. Eastern
Standard Time on the first day of the calendar month and ending at 8:00 a.m.
Eastern Standard Time on the first day of the next succeeding calendar month.
1.34. The term "NEB" shall mean the National Energy Board of Canada. 1.35. The
term "NOVA" shall mean NOVA Corporation of Alberta, or its successor in
interest.
1.36. The term "NWT Reserves" shall mean those reserves of gas underlying lands
of Seller located in the Northwest Territories which are dedicated to this
Contract and which have, for the purposes of this Contract, established reserves
using NEB standards not in excess of 830 l06m3 (29.3 Bcf).
1.37. The term "Prime Rate" shall mean the rate
of interest per annum established from time to time as its prime commercial
lending rate by the Chase Manhattan Bank, N.A. at its head office in New York.
1.38. The term "Seller's Lands" shall mean the undivided working interest in and
to the designated geological formations and/or members underlying the lands
described in Exhibit "A" attached hereto.
1.39. The term "Seller's Reserves"
shall mean those reserves of gas underlying Seller's Lands and covered by the
Leases.
1.40. The term "TCPL" shall mean TransCanada PipeLines Limited.
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1.41. The term "103m3" shall mean one thousand (1,000) cubic metres of gas and
shall be equal to 35.301 Mcf.
1.42. The term "l06m3" shall mean one million (1,000,000) cubic metres of gas.
1.43. The term "Third Party Sales" shall mean sales of gas from Seller's Lands
to third persons pursuant to Section 13.5.a.
1.44. The term "U.S. Regulatory Authorities" shall mean each governmental agency
or other authority in the United States of America which has jurisdiction over
the matter in question, including without limitation the Office of Fossil Energy
of the Department of Energy ("OFE"), the Federal Energy Regulatory Commission
("FERC") and other state and federal agencies, so long as and to the extent that
such agencies and authorities have jurisdiction over the matter in question.
1.45. The term "year" shall mean any period of twelve (12) consecutive months.
ARTICLE 2. CONTRACT QUANTITIES; DELIVERIES
2.1 Seller shall sell and cause to be delivered and Buyer shall purchase and
cause to be received on each day the Daily Nomination up to the Maximum Daily
Quantity.
2.2. If, during any period of at least 120 consecutive days after the
Commencement of Firm Deliveries Seller fails for any reason, other than force
majeure, to deliver to Buyer at least ninety percent (90%) of the sum of the
Daily Nominations for the 120-day period, then Buyer shall have the right, but
not the obligation, to elect within 90 days after the expiration of such 120-day
period to reduce the Maximum Daily Quantity under this Contract by a quantity of
gas equal to the
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average of the differences between the Daily Nominations and the actual
deliveries of gas hereunder during such 120-day period. In the event that the
Maximum Daily Quantity is reduced pursuant to this Section 2 and Buyer arranges
for delivery of a substitute supply of gas from a third-party supplier, Buyer
shall have the gas substitution rights and Seller shall have the obligations set
forth in Sections 14.7 and 14.8.
2.3. Except as otherwise provided in this Contract, and except in the event that
(a) the NEB issues a license and/or permit which is insufficient to authorize
the sale, purchase and export of the full quantities of gas provided for in this
Contract or (b) the AEUB fails to issue a removal permit or issues a removal
permit which is less than a Minimum Removal Permit and the relevant cure period
to obtain a Minimum Removal Permit shall have expired, Buyer shall not enter
into any gas supply contract for Buyer's Plant with a term greater than one year
with third party gas suppliers which exceed the volume of gas required for
Buyer's Plant to generate 79.9 megawatts of electricity under design conditions,
nor shall Buyer purchase Canadian gas in lieu of any quantities of gas tendered
by Seller up to the Maximum Daily Quantity.
2.4. On any day after the Commencement of Firm Deliveries if Buyer makes a Daily
Nomination of less than the Maximum Daily Quantity, Buyer agrees, insofar as may
be permitted under Buyer's transportation contracts and subject to the terms and
conditions thereof and the receipt of all necessary approvals from United States
Regulatory Authorities and Canadian Regulatory Authorities, to make available
for the transportation of Seller's gas, subject to interruption by Buyer to
operate Buyer's Plant, so long as Buyer is purchasing gas under this Contract,
Buyer's unutilized transportation rights; provided that Seller pays all the
transportation
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commodity charges per 103m3 (or other applicable units of measurement) payable
by Buyer for all such transportation rights of Buyer; provided, however, that
Buyer shall have no obligation to make such transportation rights available to
Seller in the event that Buyer's project lenders exercise any remedies under
Buyer's loan agreement or other loan documents.
ARTICLE 3. DELIVERY POINT
3.1 The gas purchased hereunder is to be delivered by Seller to Buyer at the
Delivery Point. It is understood that Buyer's request for the Daily Nominations
shall be made by TCPL for Buyer's account and that gas sold hereunder by Seller
shall be delivered by NOVA to TCPL for Buyer's account and not for TCPL's own
account. Volumes delivered at the Delivery Point for Buyer's account shall be
determined by the meters of TCPL at the Delivery Point. Buyer shall forward to
Seller copies of TCPL's metering statements within three (3) business days of
Buyer's receipt thereof.
ARTICLE 4. DELIVERY PRESSURE
4.1 Seller shall cause NOVA to deliver the natural gas to TCPL at the Delivery
Point at the Delivery Pressure.
ARTICLE 5. COMMENCEMENT OF SALES AND DELIVERIES
5.1 Firm deliveries shall commence hereunder upon the first Daily Nomination
made by Buyer after the Date of Firm Transportation. Such date of the first
Daily Nomination shall be the "Commencement of Firm Deliveries".
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5.2. Buyer and Seller acknowledge that the Date of Firm Transportation and the
date of the first Daily Nomination occurred on November 1, 1992.
5.3. Seller agrees to use all reasonable efforts with NOVA and Buyer agrees to
use all reasonable efforts with TCPL and United States Transporter(s), to have
constructed, installed, and made operational in a timely fashion any facilities
required for the firm delivery of gas to be sold hereunder to operate Buyer's
Plant.
ARTICLE 6. TERM OF CONTRACT
6.1.a. The amendment and restatement of the Original Gas Purchase Contract
embodied in this Contract shall become effective (the "Effective Date") upon the
later of (i) the approval of this Contract by the NEB and the AEUB as may be
required under applicable law and (ii) the date on which Buyer's restructuring
with Niagara Mohawk Power Corporation for Buyer's Plant becomes effective, in
respect of which Buyer shall forthwith deliver to Seller an irrevocable notice
from Buyer to Seller. On and after the Effective Date, the Original Gas Purchase
Contract as amended hereby and as restated herein shall govern the relationship
of Buyer and Seller. Buyer and Seller agree that the rights and obligations of
the parties prior to the Effective Date have been and are governed by the
Original Gas Purchase Contract prior to giving effect to the amendment and
restatement of the Original Gas Purchase Contract embodied in this Contract, and
Buyer and Seller expressly reserve all rights accrued under the Original Gas
Purchase Contract prior to the Effective Date.
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6.1.b. If the Effective Date has not occurred by August 31, 1998
(as such date may be extended, but only by mutual agreement of Buyer and
Seller), this Contract shall terminate without further action of either party
and be deemed void ab initio, and the Original Gas Purchase Contract shall
continue to be in full force and effect in accordance with its terms without
regard to this Contract.
6.2 This Contract shall continue in full force and effect until:
6.2.a. Fifteen (15) years after the date of Commencement of Firm
Deliveries hereof ("primary term"); provided, however, that Buyer shall have the
right, exercisable by notice to Seller delivered by the end of the tenth
contract year hereunder, to enter into a new gas purchase contract in the form
attached as Exhibit E hereto (the "New Contract") for a term of four (4) years
(or five (5) years upon mutual agreement of Buyer and Seller) (the "New Term"),
subject to the receipt of all authorizations of U.S. and Canadian Regulatory
Authorities necessary for the parties to perform their obligations under the New
Contract. Notwithstanding Buyer's exercise of its right to enter into the New
Contract, Buyer shall have the right to terminate the New Contract, before or at
any time during the New Term upon delivery of not less than twelve (12) month's
advance written notice to Seller.
6.2.b. Such earlier date as may be required to conform with an
applicable authorizations of United States and Canadian Regulatory Authorities
or any extensions thereof which are necessary for the parties hereto perform
their obligations under this Contract.
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6.3 If at any time following the approval of this Contract by the AEUB and for
the life of this Contract, Seller has less than a Minimum Removal Permit, Seller
shall, within one year from the first day of the applicable contract year,
obtain a Minimum Removal Permit. Failure to cure a shortfall in the Minimum
Removal Permit within the one year cure period provided in the preceding
sentence shall constitute a material breach by Seller giving rise to the
remedies set forth in Article 22 of this Contract.
6.4.a. Seller and Buyer agree to use their best efforts to obtain, maintain and
extend applicable authorizations of United States and Canadian Regulatory
Authorities to permit the full performance of this Contract, including but not
restricted to (1) Section 2.4, (2) the removal from the Province of Alberta of
the full quantities of gas contracted for in this Contract in accordance with
the terms hereof, and (3) the export from Canada and into the United States of
at least 15,000 Mcf of gas per day.
6.4.b. (i) Seller shall be responsible for carriage of any
application to obtain or extend the Minimum Removal Permit, provided that Seller
and Buyer shall be co-applicants, Seller shall use due diligence to ensure that
written communication from the AEUB is directed to both Buyer and Seller, Seller
shall provide Buyer with copies of all material sent to the AEUB within three
(3) business days of such delivery, and Seller shall inform Buyer of the status
of applications as developments occur. Buyer shall use due diligence to provide
Seller with information requested by the AEUB which Seller does not have
available to it and which Buyer has available to it.
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(ii) Neither Buyer nor Seller shall do any acts to change,
alter or vary the AEUB removal permit, or any extension or amendment thereof,
except as provided herein, without the consent of the other, irrespective of
whether the removal permit as issued or amended is in the name of Buyer or
Seller alone.
6.4.c. (i) Buyer shall be responsible for carriage of any application
to obtain or extend the NEB export license. Buyer shall provide Seller with
copies of all material sent to or received from the NEB within three (3)
business days of transmittal or receipt, as the case may be, and Buyer shall
inform Seller of the status of applications as developments occur. Seller shall
use due diligence to provide Buyer with information requested by the NEB which
Buyer does not have available to it and which Seller has available to it.
(ii) Neither Buyer nor Seller shall do any acts to change,
alter or vary the NEB export license, or any extension or amendment thereof,
which would impair such NEB export license without the consent of the other.
ARTICLE 7. PRICE
7.1 Upon the Commencement of Firm Deliveries and thereafter for the term hereof
as provided in Article 6, Buyer shall pay to Seller (a) a Variable
Transportation Charge determined in accordance with Section 7.3, (b) a Commodity
Charge determined in accordance with Sections 7.4 and 7.5, and (c) a Gas
Inventory Charge determined in accordance with Section 7.6. The "Price" per
month for gas service hereunder shall be the sum of the Variable Transportation
Charge multiplied by the total quantity of gas delivered to TCPL hereunder on
that month, the Commodity Charge multiplied by the total quantity of gas
delivered to TCPL hereunder in that month and the
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Gas Inventory Charge. For purposes of determining the Variable Transportation
Charge, "NOVA Charge" means the total charge in Canadian dollars paid per month
by Seller to NOVA for transportation capacity to Empress, Alberta of a quantity
of gas equal to the Maximum Daily Quantity for each day in such month, subject
to normal monthly adjustments by NOVA, provided (i) that the ratio of Seller's
receipt point demand to Delivery Point demand shall not exceed 1:1; and (ii)
that such charge excludes specific facilities charges.
7.2. All charges shall be expressed in United States dollars for purposes of
determining the Price. Any necessary conversions from either United States or
Canadian currency with respect to any charges for any month shall be: (a)
calculated at the rate of exchange published in the "Canadian Gas Price Reporter
Table: Monthly Canadian and U.S. natural gas price summary" for such month; or
(b) calculated in the manner that may be prescribed from time to time by
Canadian Regulatory Authorities.
7.3. The Variable Transportation Charge for gas delivered to TCPL hereunder in
any month shall be the NOVA Charge per 103m3, calculated on the
basis of 100% load factor, for such month, payable monthly in accordance with
Article 8.
7.4.a. The Commodity Charge per MMBtu for gas delivered in any month, payable
monthly in accordance with Article 8, shall be the amount determined in
accordance with the following formula:
CC = ABP - VTC
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Where:
"CC" is the Commodity Charge;
"ABP" is the Adjusted Base Price for such month and shall be equal to the
current month's "Avg. Border (Empress) "Bid Week" Average Spot (One Month) Firm
(100% LF) price" published in "The Canadian Gas Price Reporter Table: Canadian
Natural Gas Supply Prices" converted from Cdn $/GJ to Cdn $/MMBtus by
multiplying by 1.054615 GJ/MMBtu and converted to US $/MMBtu by multiplying by
the current month "Canada/U.S. Exchange Rate" published in "The Canadian Gas
Price Reporter Table: Monthly Canadian and U.S. natural gas price summary"
rounded to the nearest cent;
"VTC" is the Variable Transportation Charge for such month converted to U.S.
dollars per GJ pursuant to Sections 7.2 and 7.11.
7.5 In the event that any specific pricing index or publication referred to in
this Section 7 is discontinued, the parties shall promptly agree on a substitute
pricing index or publication which is equivalent to the discontinued pricing
index or publication. Such agreement shall be reflected in a mutual exchange of
letters deemed to amend this Contract for such limited purpose. In the event the
parties are unable to reach agreement as to a substitute pricing index or
publication, the matter shall be resolved by arbitration in accordance with
Article 20 hereof.
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7.6 7.6.a. The Gas Inventory Charge for any month shall be equal to the NOVA
Charge less the product of (i) the Variable Transportation Charge multiplied by
(ii) the total quantity of gas delivered hereunder to TCPL during such month.
Seller shall invoice Buyer for the Gas Inventory Charge in Buyer's bill rendered
pursuant to Article 8 immediately following the completion of such month subject
to any subsequent monthly adjustments made by NOVA in respect of the NOVA
Charge.
7.6.b. If Seller or NOVA fails to tender to TCPL, wholly or in part, the
Daily Nomination hereunder, Buyer shall be relieved of its obligations to pay
the Gas Inventory Charge to the extent of such failure, calculated as follows:
the Gas Inventory Charge for any month in which deliveries are impaired shall be
reduced by an amount equal to the product of (i) the Variable Transportation
Charge and (ii) the difference between the total of the Daily Nomination on each
day of such month minus the total quantity of gas delivered hereunder to TCPL
during such month.
7.6.c. The Gas Inventory Charge for any month shall be further reduced by
an amount equal to the product of (i) the quantity of gas per 103m3 based on the
transportation rights elected to be used by Seller pursuant to Section 2.4 of
Article 2 and (ii) the Variable Transportation Charge.
7.7 Upon Commencement of Firm Deliveries, the minimum monthly bill shall be the
NOVA Charge.
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7.8 Any conversion from volume units to heating units required for the purpose
of this Article 7 shall be based on the average heating value in the month of
delivery of the gas received by TCPL at the Delivery Point for the account of
Buyer.
ARTICLE 8. BILLINGS AND PAYMENTS
8.1 Subject to Seller's receipt of TCPL's metering statements pursuant to
Article 3 hereof, Seller shall render to Buyer on or before the tenth (10th) day
of each month after the first sale of gas hereunder a statement for the
preceding month in which the gas being billed for was sold (the "Sale Month")
showing the daily and total quantity of gas sold hereunder, the weighted average
Heating Value per cubic metre thereof, the applicable Price (determined pursuant
to Article 7), and the total amount payable to Seller therefore stated in United
States dollars (the "Sum"). Buyer agrees to deposit in Seller's account at the
Bank of Montreal, Main Branch in Calgary, Alberta, Canada, on or before the
twenty-fifth (25th) day of each such month, the Sum for the Sale Month. In the
event that Seller fails to render a statement to Buyer on or before the tenth
(10th) day of a month, the date by which Buyer must deposit the Sum in Seller's
account shall be extended one day for each day Seller's statement is late;
provided, however, that if Seller is unable to render a statement on or before
the tenth (10th) day of a month, Seller may at its option render an estimated
statement to Buyer which statement shall contain Seller's best estimate of the
daily and total quantity of gas sold hereunder during the preceding month, the
weighted average Heating Value per cubic metre thereof, and the total amount
payable by Buyer therefore stated in United States dollars. Buyer shall deposit
in Seller's account the Sum for such estimated statement within fifteen (15)
days of its receipt but no sooner than the 25th day of the month. For any month
in which Seller renders an estimated statement to Buyer, Seller shall render the
final statement for
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such month with Seller's statement for the next succeeding month. Seller's
statement for such next succeeding month shall reflect an adjustment for any
difference between the estimated statement and the final statement for the
previous month, which shall be added to or deducted from, as appropriate,
Seller's statement for such next succeeding month. If Buyer fails to deposit the
Sum or any portion thereof, in Seller's account when same is due, interest
thereon shall accrue at the annual rate of interest which is equal to the sum of
two percent (2%) plus the Prime Rate until the same is paid.
8.2. If Buyer's failure to pay continues for thirty (30) days, Seller, in
addition to all other remedies, may thereafter suspend the sale of gas hereunder
and if such default continues for thirty (30) additional days, Seller may
thereafter, in addition to any other rights Seller may have, terminate this
Contract; provided, however, in order for Seller to have the right to suspend
sales or terminate this Contract, Seller must first have notified Buyer in
writing fifteen (15) days prior to exercising such right of its intent to do so
and give Buyer the right to pay the amount so due to Seller within such fifteen
(15) day period; and provided, further, that if Buyer in good faith shall
dispute the amount of any such bill or any part thereof and shall pay to Seller
such amounts as it concedes to be correct and at any time thereafter within
twenty (20) days of a demand made by Seller shall furnish or cause to be
furnished a good and sufficient surety bond satisfactory to Seller, guaranteeing
payment to Seller of the amount ultimately found due upon such bill after a
final determination which may be reached either by agreement or judgment of the
courts, as may be the case, then Seller shall not be entitled to suspend further
sales of gas because of such nonpayment unless and until default be made in the
conditions of such bond.
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8.3. Each party shall have the right to inspect and examine at all reasonable
times the records and charts of the other party pertaining to the purchase and
sale of gas hereunder. If any overcharge or undercharge in any amount whatsoever
shall be found within two (2) years of the date of billing and the bill
therefore has been paid, Seller shall refund the amount of the overcharge or
Buyer shall pay the amount of the undercharge within thirty (30) days after the
final determination thereof, with interest thereon for the period the overcharge
or undercharge was outstanding calculated at the annual rate of interest which
is equal to the sum of two percent (2%) plus the Prime Rate. This Section 8.3
shall survive termination of this Contract.
ARTICLE 9. QUALITY
9.1 Seller agrees to sell and cause to be delivered and Buyer agrees to purchase
and cause to be received at the Delivery Point, gas which shall meet the quality
specifications set forth in the TCPL tariff governing the transportation of the
gas sold hereunder.
9.2. If the gas offered for delivery hereunder by Seller shall fail at any time
to conform to any of the specifications identified in Section 9.1, then Buyer
shall notify Seller of such deficiency and thereupon may, at Buyer's option,
refuse to purchase such gas pending correction by Seller. Upon Seller's failure
promptly to remedy any such deficiency in quality, Buyer may purchase such gas
and may make changes necessary to bring such gas into conformity with such
specifications, and Seller shall reimburse Buyer for any reasonable expense
incurred by Buyer in effecting such changes.
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ARTICLE 10. MEASUREMENT OF GAS
10.1 Seller and Buyer agree that the measurement of the gas to be delivered by
Seller and received by Buyer at the Delivery Point shall be determined by the
measurement provisions set forth in the TCPL Tariff governing the transportation
of the gas sold hereunder.
ARTICLE 11. POSSESSION AND TITLE
11.1 Possession of and title to gas sold by Seller to Buyer hereunder shall pass
from Seller to Buyer at the Delivery Point. Until the gas reaches the Delivery
Point, Seller shall be deemed to be in control of and have title to and
possession of and be responsible for such gas, after which Buyer shall be deemed
to be in control of and possession of and have title to and be responsible for
such gas.
ARTICLE 12. SELLER'S REPRESENTATIONS AND WARRANTIES
12.1 Seller represents and warrants that: (i) it has full right and authority to
enter into this Contract; (ii) subject to the applicable laws, rules and
regulations, the Leases are in full force and effect and are capable of being
maintained and will be maintained by Seller in full force and effect for as long
as gas can be produced in paying quantities; and (iii) Seller has good title to
and the right to sell the gas to be sold and delivered hereunder and all such
gas is owned or authorized to be sold by Seller and will be delivered by Seller
free from all Alberta taxes, liens, charges and adverse claims whatsoever,
including liens to secure payment of any taxes. Seller shall at all times have
the obligation to make settlements for all royalties and overriding royalties
due and payments to the mineral and royalty owners under the Leases and
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other documents, as may appear of record or otherwise be binding upon Seller and
in accordance with the terms of the respective Leases and other documents, and
to make settlements with all other persons having any interest in the gas sold
hereunder. Seller agrees to indemnify Buyer and save it harmless from all suits,
actions, debts, accounts, damages, costs, losses, liabilities and expenses
arising from or out of claims of any other charges thereon, which attach before
the title passes to Buyer or which may be levied and assessed upon the sale
thereof to Buyer and are the responsibilities of Seller hereunder.
12.2. Seller represents that it is entitled to drill for, produce, and sell gas
from Seller's Lands. Seller warrants and represents that Seller will, subject to
and in accordance with the provisions of this Contract, equip and tie-in its
wells and construct or install its facilities so as to be able to commence and
continue delivery of gas to Buyer in accordance with the provision of this
Contract. Subject to Article 13, Seller covenants to diligently drill, develop
and produce Seller's Reserves to the extent required by Section 14.4 such that
Deliverable Gas at the time of each Determination referred to in Article 14 will
be sufficient for Seller to supply the Maximum Daily Quantity to Buyer from
Seller's Reserves for at least four (4) contract years following each such
Determination. Upon Commencement of Firm Deliveries, Seller shall deliver to
Buyer sufficient gas to meet Seller's obligations under this Contract from
Seller's Lands or from such other sources available from time to time to Seller
provided that Seller has the right and necessary regulatory approvals to deliver
to Buyer from such other sources.
12.3. 12.3.a. Seller dedicates and commits exclusively to the performance of
this Contract all of Seller's Reserves and represents to Buyer that such
Seller's Reserves will at all times (i) be sufficient in quantity and quality to
satisfy provincial and federal regulatory authorities in respect of maintaining
a provincial removal permit which satisfies the requirements of Section 6.3.a
and a
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federal export license for the full term and volumes contemplated in this
Contract; (ii) contain Initial Recoverable Reserves in an amount not less than
2,747.9 106m3 (97.01 Bcf) in accordance with Section 14.3; and (iii) contain
Deliverable Gas in an amount not less than the Minimum Deliverable Gas Amount in
accordance with Section 14.4. Seller's Reserves shall not be named or used by
Seller or any third party to support any removal permit or export license other
than the joint removal permit and the export license to be obtained by Buyer
based on Seller's Reserves to permit gas purchased hereunder to be removed from
the Province of Alberta and delivered to Buyer.
12.3.b. Buyer is hereby authorized by Seller to identify and commit
Seller's Reserves in order to jointly obtain with Seller or extend a provincial
removal permit and to obtain on its own behalf or extend a NEB export license in
respect of the Maximum Daily Quantity for the term of this Contract. Seller
agrees to cooperate with Buyer and provide Buyer with such further information
concerning Seller's Reserves as may be required for such purposes.
12.3.c. During the term of this Contract, Seller shall not sell, assign,
transfer or otherwise dispose of any interest in Seller's Reserves without
obtaining Buyer's prior written consent, such consent not be unreasonably
withheld. Seller acknowledges that a reasonable condition to Buyer providing any
such consent would be the assumption (by novation or other means acceptable to
Buyer) by such third party of that portion acquired by such third party of
Seller's obligations to Buyer under this Contract.
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12.3.d. Seller represents that no finding of producer support under the
Alberta Natural Gas Marketing Act nor any joint working interest owner approval
is or will be necessary for Seller to fulfill its obligations under the terms
and conditions of this Contract.
ARTICLE 13. SELLER'S RESERVATIONS
13.1 Seller hereby expressly reserves unto itself the following rights:
13.1.a. to operate Seller's Lands and Seller's Reserves free from any
controls by Buyer and in such manner as Seller in its sole discretion may deem
advisable consistent with good oilfield practice, including but not restricted
to, the right to determine when and whether any additional well will be drilled,
when and whether any well will be reworked or recompleted, when and whether any
lease or well cannot or has ceased to produce gas in paying quantities having
regard to Seller's cost of producing, processing and delivering such gas and
when and whether any lease or well is to be released or abandoned or
surrendered;
13.1.b. to determine the manner in which the quantities of gas to be
delivered hereunder shall be produced by Seller from the various wells on
Seller's Lands; and
13.1.c. to deliver to any lessors of the Leases the quantities of gas which
Seller is obligated to deliver in kind to such lessors.
13.2 Seller reserves unto itself the following quantities of gas from Seller's
Lands:
13.2.a. such gas (other than gas used as fuel in thermal recovery
operations) as may be required for the development and operation of Seller's
Lands, including but not limited to gas
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for gas lifting operations and return to reservoir, so long as such gas lifting
operations and return to reservoir do not interfere with Seller's ability to
deliver gas under this Contract; and
13.2.b. such gas as may be required for the operation of separator
equipment, compressor stations and other facilities through which the gas to be
delivered hereunder may be processed or handled; provided, however, that if
other gas or gas constituents are processed through any of the foregoing
facilities, an equitable amount of such other gas or gas constituents shall be
used in such facilities.
13.3 For the purpose of causing the gas to be delivered to meet the quality
specifications set forth in Article 9 hereof, Seller may extract or permit the
extraction of non-hydrocarbon and hydrocarbon constituents as are required to be
extracted in order for the gas to meet such specifications.
13.4. Seller shall not be required to produce wells in excess of the lesser of:
(a) their respective allowable rates of flow as fixed by law or regulatory
bodies; (b) their maximum efficient rates of flow as determined by Seller; or
(c) in instances of wells jointly operated with other parties, the current rate
of production permitted Seller under the terms of applicable operating
agreements.
13.5 13.5.a. Seller shall have the right on any day to make Third Party Sales in
an amount up to the Maximum Daily Quantity provided (i) Seller shall have met
Buyer's Daily Nomination on such day and (ii) neither a Reserve Deficiency nor a
Deliverability Deficiency that must be cured pursuant to Section 14.4 then
exists. Seller may accumulate its daily right to make Third Party Sales during
each calendar month, and amounts so accumulated may be sold on any
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day during such calendar month and the following calendar month in addition to
the daily limit for such day. With respect to any amount for which Seller has
accumulated its daily right to make Third Party Sales, Seller shall have no
further right to make Third Party Sales of such amount after the two month
period applicable to such amount has elapsed. Notwithstanding the foregoing,
Seller shall in no event make Third Party Sales before meeting Buyer's Daily
Nominations on any day, and in no event shall Seller make Third Party Sales in
an amount exceeding a quantity equal to (a) the product of (i) the number of
days in the relevant two-month period and (ii) the Maximum Daily Quantity, less
(b) the sum of any Daily Nominations made by Buyer in such months.
13.5.b. In addition to Third Party Sales as provided in Section 13.5.a.,
Seller shall have the right to make Excess Third Party Sales on any day provided
(i) Seller shall have met Buyer's Daily Nomination on such day and (ii) neither
a Reserve Deficiency nor a Deliverability Deficiency that must be cured pursuant
to Section 14.4 then exists.
13.6 Seller may pool or unitize any of Seller's Lands with other properties and,
if any of Seller's Lands are so pooled or unitized, this Contract will cover
Seller's interest in the unit derived therefrom and the gas attributable
thereto; provided, however, that in the event that such pooling or unitization
is entered into voluntarily by Seller, it shall protect Buyer's rights hereunder
and prevent an appreciable reduction or postponement in the Article 2 quantities
of gas to be sold by Seller to Buyer.
Buyer and Seller agree that, from time to time as appropriate, they shall
negotiate in good faith to agree upon appropriate action under or with respect
to this Contract to maintain or improve
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alignment of deliverability of Seller's Reserves, consistent with the efficient
administration of Seller's lands and reserves and the full performance of this
Contract, and subject to the receipt of all necessary regulatory approvals,
which necessary regulatory approvals shall not adversely affect any existing
approval required under this Contract.
ARTICLE 14. ASSURANCES OF GAS SUPPLY; SUBSTITUTE GAS SUPPLY
14.1 On or before the date upon which Seller proposes to make a reduction
pursuant to Section 14.9 and on or before each September 1 during the term of
the Contract, Seller shall provide to Buyer, at Seller's expense, a written
reserves and deliverability report ("Report"). Each Report shall be prepared by
McDaniels Associates ("McDaniels") or another independent reserve engineer
reasonably acceptable to Buyer. Seller shall notify Buyer in writing not less
than three (3) months prior to the delivery of a Report if Seller intends to
employ an independent reserve engineer other than McDaniels and Buyer shall have
thirty (30) days to accept or reject said independent reserve engineer. In
addition, Buyer may inform Seller that McDaniels, or an independent reserve
engineer subsequently selected, as the case may be, is no longer an acceptable
independent reserve engineer with respect to the next due Report upon written
notice given not later than the February 1 of the year in which such Report is
to be delivered. If Seller and Buyer are unable to agree upon a substitute
independent reserve engineer, the selection of an independent reserve engineer
shall be submitted to arbitration pursuant to Article 20. If Buyer and Seller
are unable to agree upon a substitute independent reserve engineer, or if
arbitration has not determined a substitute independent reserve engineer, in
either case, by September 1 of any year, Seller shall nevertheless provide the
Report due on such September 1, which Report shall have been prepared by the
independent reserve engineer which prepared the prior year's Report. Failure to
agree on an
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independent reserve engineer, by negotiation or arbitration, shall not excuse
Seller's failure to provide a Report on or before September 1 of each year.
Each Report shall redetermine and set forth the Initial Recoverable
Reserves as of the first day of the contract year immediately following the
Report. Each Report shall also determine and set forth the Deliverable Gas as at
the date of such Report under this Contract for each contract year for the
remainder of the Contract term. Each Report shall also set forth Seller's best
estimate of the cost to drill and develop additional lands and reserves
necessary to cure a Deliverability Deficiency (as defined in Section 14.4) (the
"Tie-in Cost") together with, when applicable, the information required under
Section 14.4 and Section 14.9.
14.2 Buyer shall, within 45 days of receipt of a Report, advise Seller whether
such Report is acceptable to Buyer and if it is acceptable to Buyer, such Report
shall become the "Determination" for purposes of this Article 14. In the event
that Buyer advises Seller that such Report is not acceptable, Seller and Buyer
shall endeavor to agree upon a mutually acceptable Initial Recoverable Reserves,
Deliverable Gas, estimate of the Tie-in Cost, and land removal determination. In
the event that Seller and Buyer do so agree, their determination shall be in
writing, shall set forth the Initial Recoverable Reserves, Deliverable Gas,
estimate of
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the Tie-in Cost, and land removal determination, and shall be the
"Determination" for purposes of this Article 14. In the event that Seller and
Buyer are unable to agree upon a mutually acceptable Initial Recoverable
Reserves, Deliverable Gas, estimate of the Tie-in Cost, and land removal
determination, either party may, within 90 days of delivery of Report, refer the
matter to arbitration pursuant to Article 20 hereof. An Initial Recoverable
Reserves, Deliverable Gas, estimate of the Tie-in Cost, and land removal
determination by arbitration shall be in writing, shall set forth the Initial
Recoverable Reserves, Deliverable Gas, estimate of the Tie-in Cost, and land
removal determination and shall be the "Determination" for purposes of this
Article 14.
14.3 If a Determination states that the Initial Recoverable Reserves are less
than 2,747.9 106m3 (97.01 Bcf), as adjusted to reflect on a proportionate basis,
any decrease in the Maximum Daily Quantity under the Contract (a "Reserves
Deficiency"), then, within twelve (12) months of the first day of the contract
year immediately following the Report upon which the Determination is based,
Seller shall dedicate additional lands and reserves to this Contract as needed
to cure the Reserves Deficiency.
14.4. 14.4.a. If any Determination indicates that Deliverable Gas during the
first full five (5) contract years of 12 months each detailed in the Report upon
which the Determination is based is less than the Minimum Deliverable Gas Amount
(a "Deliverability Deficiency"), then, within twelve (12) months of the first
day of the contract year immediately following such Report, Seller shall either
(i) increase the deliverability from Seller's Reserves and, if necessary,
dedicate additional lands and reserves to this Contract, as needed to cure the
Deliverability Deficiency or (ii) provide a binding written certification that
it reasonably believes that it can obtain gas from other sources ("Alternate
Sources") to meet its obligations under this Contract and that it has the right
and necessary regulatory approvals to deliver such gas to Buyer (an "Alternate
Source Notice").
14.4.b. The Alternate Source Notice shall provide in reasonable detail the
facts underlying such Notice and shall identify the extent to which Seller
intends to rely on Alternate
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Sources. Seller shall not be entitled to seek excuse from its obligation to cure
a Deliverability Deficiency as otherwise permitted pursuant to Section 14.4.c.
for any period for which an Alternate Source Notice is given. All of the terms
and conditions of this Contract (including, without limitation, Seller's duty to
supply the Maximum Daily Quantity and the pricing terms with respect thereto)
shall continue unaffected by the Alternate Source Notice. Seller shall not be
entitled to deliver an Alternate Source Notice for any Deliverability Deficiency
relating to volumes attributable to Excess Third Party Sales. If for any reason,
Seller is unable to meet at any time Buyer's nomination for gas up to the
Maximum Daily Quantity and Seller has provided an Alternate Source Notice for
such period and Buyer is unable to use NOVA transportation otherwise available
to it under Section15.3 through no fault of its own, thenSeller shall thereafter
not be entitled to rely on the Alternate Source Notice in lieu of increasing the
deliverability from Seller's Reserves, but shall thereupon immediately be
obligated to cure the Deliverability Deficiency in accordance with Section
14.4.a.(i) and Section 14.11.
14.4.c. Seller shall be excused from its obligation to cure a
Deliverability Deficiency pursuant to this Section 14.4, but only to the extent
that the Deliverability Deficiency is not the result of Excess Third Party
Sales, if:
(a) The Determination provides Buyer with at least four (4) years advance
notice that beginning with the fifth (5th) contract year following such current
Determination, that deliverability from Seller's Reserves will be insufficient
for Seller to meet its Maximum Daily Quantity delivery obligations to Buyer
hereunder; and
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(b) The Determination demonstrates that for a period of at least twelve
(12) consecutive months the weighted average price of gas under this Contract is
not greater than or equal to the price (the "Sufficient Acquisition Price")
which would be necessary in order that additional gas supplies can be acquired
and produced to cure the Deliverability Deficiency; and
(c) Buyer does not agree within six (6) months of the Determination
referred to in subsection (b) to increase the Price under the Contract for the
Deliverability Deficiency to the Sufficient Acquisition Price effective from and
after the first month of the Deliverability Deficiency.
The Sufficient Acquisition Price shall, until a contrary Determination
pursuant to Section 14.4.b, be deemed to be equal to the Price under this
Contract. In the event that Seller intends to claim that the weighted average
price of gas under this Contract is not greater than or equal to the Sufficient
Acquisition Price, Seller shall instruct its independent reserve engineer to
include as part of the Report which Seller proposes to be the basis of the
Determination referred to in Section 14.4.b a full and true accounting which:
(i) identifies the lands and reserves which are controlled by or could with
reasonable diligence become controlled by Seller and used to supply the Contract
(the "Available Lands"); and (ii) and provides Seller's least cost estimate
(exclusive of any return on monies invested) to drill, develop, process and
produce from each of the Available Lands in a manner which would cure a
projected Deliverability Deficiency in whole or in part ("Net Development
Costs"). For the purposes of estimating Net Development Costs, Seller's estimate
of the cost to drill and develop the Available Lands included in such Net
Development Costs for each of the Available Lands shall be reduced by 25%. Upon
receipt of this
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accounting and as part of such Report, Buyer and its agents shall be entitled to
attend at the offices of Seller and examine all title documents relating to the
Available Lands, historical information and any other data used by Seller to
establish its Net Development Costs including the audited and unaudited
accounting and record books of Seller, it being understood that Buyer shall keep
such information as is requested by Seller confidential except as required for
the purposes of this Contract. Following Buyer's audit, Buyer and Seller shall
use reasonable efforts to agree to a Sufficient Acquisition Price failing which
the matter shall be determined pursuant to arbitration invoked with respect to
the Report in accordance with Section 14.2. The Arbitrator shall consider and
determine the Sufficient Acquisition Price based on the costs, exclusive of any
return on monies invested, of Seller developing the Available Lands to satisfy a
Deliverability Deficiency, together with any evidence adduced by the parties and
relevant to the determination.
14.5 In the event that Seller cures a Reserve Deficiency or a Deliverability
Deficiency (each a "Deficiency") for any given year prior to the expiration of
the respective cure periods provided in Sections 14.3 and 14.4 (each, a "Cure
Period"), Seller shall provide Buyer immediate written notice thereof, to be
confirmed within 60 days by an additional Determination. Once the Cure Period
for any contract year for which the Determination projects a Deficiency begins
to run, the length of such Cure Period shall not be altered by any subsequent
Determination.
14.6 In each contract year that Seller issues a Report, Buyer shall be entitled
to elect by written notice to Seller, to be made within forty-five (45) days of
the receipt by Buyer of a Report in such contract year, to review the contracts
and other documents and technical information that are relevant to such Report.
Upon receiving such notice, and subject to Seller's reasonable needs to
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maintain the confidentiality of any information, Seller shall permit Buyer, its
agents and advisors to conduct such review, provided that such review shall be
completed within forty-five (45) days of the date on which Seller has made
available such relevant contracts and documents.
14.7 14.7.a In the event that the Maximum Daily Quantity is reduced under this
Contract, Buyer may arrange a substitute supply of gas or other fuel supplies
equal to all or part of the portion of the Maximum Daily Quantity which is
reduced.
14.7.b. Buyer and Seller shall use their best efforts to secure all
necessary regulatory approvals to implement delivery of any substitute gas
supply by any third-party supplier or suppliers in the event the Maximum Daily
Quantity is reduced for whatever reason pursuant to this Contract with the
understanding that any provincial removal permit held by Seller and/or Buyer
shall be sought to be utilized (by transfer, assignment or otherwise) as
authorization of the removal and export by any third party supplier or suppliers
of any substitute gas supplies. Buyer and Seller agree to use their best efforts
to assist in accomplishing such transfer or assignment.
14.7.c. Upon notice by Buyer to Seller that Buyer has arranged for a
substitute gas supply, Seller shall assign or otherwise-make available to each
third party supplier a corresponding quantity of firm capacity on the facilities
of NOVA or other intraprovincial pipeline and, to the extent permitted by NOVA
or such other intraprovincial pipeline, Seller's rights under its contract with
NOVA or such other intraprovincial pipeline to the extent of the substitute gas
supplies to be supplied by each third-party supplier.
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14.8 In the event that the Maximum Daily Quantity is reduced pursuant to any
provision of this Contract and Buyer obtains a substitute gas supply pursuant to
Section 14.7 or other fuel supplies to operate Buyer's Plant, and provided that
Seller's failure to cure the Deficiency is not excused pursuant to the
provisions of Section 14.4, Seller shall indemnify Buyer for: (i) any and all
costs and expenses reasonably incurred by Buyer in arranging, obtaining and
using the substitute supply of gas or other fuel to the extent that such
costs-and expenses exceed those which would have been incurred by Buyer had
Seller delivered a quantity of gas equivalent to the substitute gas supply; and
(ii) any demand charges incurred by Buyer pursuant to its transportation
contracts with TCPL and United States Transporter(s) to the extent that
transportation under such contracts is not utilized by Buyer; provided, however,
that Seller's liability pursuant to this Section 14.8 shall not exceed an amount
equal to the product of the amount of the reduction in the Maximum Daily
Quantity and the sum of the demand charges per 103m3 or other applicable units
of measurement incurred by Buyer pursuant to its transportation contracts with
TCPL and United States Transporter(s).
14.9 14.9.a. Seller and Buyer agree that not more frequently than once every
contract year, at such time as (i) Seller has a Minimum Removal Permit and (ii)
Buyer has an NEB export license for the sum of 3,681 106m3 (130 Bcf) as at
November 1, 1992, less the amount of gas which Seller is permitted to have
produced from Seller's Lands as of the date of such removal pursuant to this
Contract (i.e., Buyer's Daily Nomination plus Third Party Sales permitted
pursuant to Section 13.5), and such NEB export license authorizes the sale and
export from Canada of 424.9 103m3 (15,000 Mcf) per day for the unexpired term of
this Contract, then Seller may remove from Seller's Lands as described in
Exhibit A any lands not required to support any Canadian
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regulatory authorizations or approvals required for the performance of this
Contract, including, but not limited to, the NEB export license and the AEUB
removal permit; provided, however, that there shall have been a Determination
pursuant to Section 14.2 setting forth the information required pursuant to
Section 14.9.b (in addition to any other information required to be included in
a Determination); and provided, further, that the conditions of Sections 14.9.c
and 14.9.d have been satisfied.
14.9.b. If Seller proposes to remove from Seller's Lands any lands as
described in Section 14.9.a, there must first have been a Determination which,
in addition to any other information required to be included in a Determination,
(i) identifies the lands and reserves proposed to be removed pursuant to Section
14.9.a and the lands and reserves to remain dedicated to this Contract, (ii)
establishes that deliverability from the remaining Seller's Reserves, tied-in
and producing or in respect of which a letter of credit or letters of credit
have been posted for the Tie-in Cost are sufficient for Seller to meet its
Maximum Daily Quantity delivery obligations to Buyer hereunder for the then next
five (5) full contract years of at least twelve (12) months; (iii) establishes
that not less than 67% of the Seller's Reserves after the proposed removal are
proven reserves and the remainder are probable reserves using NEB/AEUB
standards; and (iv) demonstrates that Seller's Tie-in Cost for the remaining
Seller's Reserves is not increased by the proposed removal.
14.9.c. No removal of lands pursuant to this Section 14.9 shall be
permitted until (i) any letter(s) of credit required in connection with the
applicable Determination shall have been posted, (ii) all regulatory approvals
necessary for the removal of the proposed lands from this
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Contract and from any existing permit required for the performance of this
Contract, including, but not limited to, the NEB export license and the AEUB
removal permit, shall have been received, and such necessary regulatory
approvals shall not adversely affect any existing permit required for the
performance of this Contract, including, but not limited to, the NEB export
license and the AEUB removal permit and (iii) the Cure Gas Amount, if any, has
been satisfied in accordance with Section 22.3.
14.9.d. Seller may not remove tied-in and producing Seller's Reserves
pursuant to this Section 14.9 unless the remaining Seller's Reserves, tied-in
and producing, are sufficient for Seller to maintain the Minimum Removal Permit.
Buyer agrees to do such acts as are necessary to evidence Seller's removal
of Lands completed in accordance with this Section 14.9.
14.10. In the event that, at any time, Buyer and Seller agree to remove lands
from Seller's Lands and substitute additional different lands ("Reserve
Substitution"), the parties shall use reasonable efforts to effect Reserve
Substitution in a manner which provides Buyer with sufficient security that the
Maximum Daily Quantity will be met for the remaining term of the Contract. In
order to allow Buyer to assess a proposed substitution of reserves Seller shall
provide Buyer with full information as may be requested by Buyer on the reserves
to be added as a result of the Reserve Substitution. Buyer shall evaluate and
determine whether the Reserve Substitution provides it with sufficient security
of supply. In the event that Buyer and Seller cannot agree as to the Reserve
Substitution the matter shall be determined by arbitration on the basis of
providing Seller with the ability to produce up to the Maximum Daily Quantity
from the Seller's Lands and
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provide Buyer with assurance that the Maximum Daily Quantity shall be available
for the remaining term of the Contract and on the basis that only lands of
equivalent value will be substituted and, further, that seller's Reserves
following any such Reserve substitution will meet the conditions of Sections
14.9.b.(ii)-(iv) (in each case, applying such conditions to the substitution
rather than the removal of lands). Seller may not replace tied-in and producing
Seller's Reserves pursuant to this Section 14.10 unless Seller's Reserves,
tied-in and producing, following such Reserve Substitution, are sufficient to
maintain the Minimum Removal Permit. Whether by agreement or by arbitration, the
Reserve Substitution shall not take effect until both the AEUB and NEB have
demonstrated to the satisfaction of Buyer that a removal permit and export
license as required under this Contract shall remain in full force and effect
notwithstanding the Reserve Substitution.
Buyer agrees to do such acts as are necessary to evidence a Reserve
Substitution completed in accordance with this Section 14.10.
14.11. 14.11.a. If a Report indicates a Deliverability Deficiency and Seller has
not provided an Alternate Source Notice continuing in effect for the period
covered by the Report or is not excused from its obligation to cure the
Deliverability Deficiency pursuant to Section 14.4, Seller shall supply to Buyer
an irrevocable letter of credit, with a term of not less than one calendar year,
substantially in the form attached hereto as Exhibit D or otherwise satisfactory
to Buyer. The letter of credit shall be transferable to the Collateral Agent or
other agent of the bondholders under Buyer's Trust Indenture dated as of May 1,
1994, as amended from time to time. Buyer and Seller shall promptly take the
necessary and appropriate actions to transfer to such agent any letter of
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credit outstanding on the Effective Date which does not on its face provide for
transfer to such agent. The letter of credit shall be issued by a financial
institution whose long-term unsecured debt securities are rated A or better by
Standard and Poor's Corporation or A or better by Dominion Bond Rating Service.
Each letter of credit shall be in the amount of the Tie-in Cost (as set forth in
the applicable Report) estimated by the independent reserve engineer for the
additional lands and reserves necessary to cure the applicable Deliverability
Deficiency; provided, however, that if Buyer does not accept such Report, the
amount of the letter of credit shall be adjusted to equal the amount of the
Tie-in Costs for the additional lands and reserves necessary to cure the
Deliverability Deficiency as set forth in the Determination, which increase or
decrease in the amount of the letter of credit shall be effected within ten
business days of such Determination, unless Seller is not obligated to cure the
Deliverability Deficiency pursuant to Section 14.4 with respect to the adjusted
Tie-in Cost.
Seller shall supply any required letter of credit within the later of (i)
forty-five (45) days of delivery to Buyer of a Report and (ii) five (5) days of
delivery to Seller of Buyer's response to such Report, unless Seller shall have
sooner cured the applicable Deliverability Deficiency as evidenced by a
Determination in accordance with Section 14.5. Seller agrees that (i) the
posting of a letter of credit by the Seller in respect of a Deliverability
Deficiency identified in a Report which is accepted by Buyer, and (ii) the
adjustment by Seller of the amount of a posted letter of credit following a
Determination in respect of the Tie-in Cost estimated by Seller in a Report
which was not so accepted by Buyer shall in each case, but not otherwise,
constitute Seller's conclusive acknowledgment that, with respect to the
Deliverability Deficiency to which
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the letter of credit relates, the Sufficient Acquisition Price for gas supplies
and reserves required to cure such Deliverability Deficiency does not exceed the
Price under this Contract.
14.1l.b. Buyer shall have the right to draw upon the letter of credit to
indemnify itself to the extent of the costs, expenses and charges recoverable by
Buyer pursuant to Section 14.8 ("Costs of Cover") if Seller has not cured the
Deliverability Deficiency, as evidenced by a Determination in accordance with
Section 14.5, required to be cured by the expiration of the Cure Period for such
Deliverability Deficiency. Buyer shall promptly return to Seller any amounts
drawn on said letter of credit in excess of the Costs of Cover.
14.1l.c. Not less than thirty (30) days prior to the expiration of such
letter of credit, Seller shall provide Buyer with written evidence of the
renewal of such letter of credit. If Seller does not renew such letter of
credit, or if Seller fails to provide evidence of the renewal of such letter of
credit by the time required pursuant to the preceding sentence, and Seller has
not previously cured the relevant Deliverability Deficiency as evidenced by a
Determination in accordance with Section 14.5, Buyer shall be entitled to draw
the full amount of such letter of credit prior to its expiration and to apply
the proceeds of such a drawing to its Costs of Cover. Buyer shall promptly
return to Seller any amounts drawn under a letter of credit in excess of the
Costs of Cover.
14.1l.d. Upon curing, in whole or in part, a Deliverability Deficiency, as
evidenced by a Determination in accordance with Section 14.5, in respect of
which a letter of credit has been posted, Seller shall be entitled, upon not
less than ten business days' notice in writing to Buyer, to have the amount of
the letter of credit reduced to the extent of the value of the cure so effected
(if
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such cure is partial only) and to withdraw the letter of credit, if the
relevant Deliverability Deficiency has been completely cured.
14.12. Seller shall provide to Buyer monthly the information required by AEUB
Form S-1, or any successor form, for the preceding month (the "Form S-1
Information") at the same time as Seller is required to provide such AEUB Form
S-1 to the AEUB. If for any reason the AEUB ceases to require Seller to submit
to the AEUB Form S-1 or any successor form, Seller shall nevertheless continue
to provide to Buyer the Form S-1 Information by the fifteenth day of each month
for the preceding month. If Seller does not provide Buyer with the Form S-1
Information when required, Buyer shall be entitled to take whatever actions are
necessary to obtain such Form S-1 Information, including examining seller's
original records upon which such Form S-1 Information is based if such Form S-1
Information is not publicly available from the AEUB in a timely fashion, and
Seller shall reimburse Buyer for Buyer's costs and expenses in obtaining such
Form S-1 Information.
14.13 Buyer shall provide to Seller, within thirty (30) days of Seller's written
request, a written estimate of the number of hours which Buyer anticipates that
the Plant will be dispatched on-line for the next following contract year. Buyer
shall not be obligated to provide such estimate more frequently than once each
contract year.
ARTICLE 15. LIABILITIES AND LIMITATION OF LIABILITIES
15.1 If Seller fails to deliver the Daily Nominations pursuant to Article 5
hereof, and Seller's failure is not excused pursuant to the provisions of
Section 16.1, Seller's sole liability to Buyer, except as set forth in Section
15.2 and Section 15.3, shall be liquidated damages equal to the
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product of the volume of gas which Seller fails to deliver and the sum of the
demand charges per 103m3 (or other applicable units of measurement) incurred by
Buyer pursuant to its transportation contracts with TCPL and United States
Transporter(s); provided, however, that in case of the Maximum Daily Quantity
becoming reduced pursuant to any provision of this Contract and Buyer obtaining
a substitute gas supply pursuant to Section 14.7 or other fuel supplies to
operate Buyer's Plant, and providing that Seller's failure to cure the
Deficiency is not excused pursuant to Section 14.4, Seller's liability to Buyer
shall be as set forth in Section 14.8.
15.2. If on any day Seller delivers more or less gas than Buyer requests, Seller
and Buyer shall cooperate in making all reasonable efforts to mitigate the
effect of same, provided, however, that in the event that Buyer, as a result of
an over-delivery or under-delivery which can reasonably be considered to be the
fault of Seller, is assessed by TCPL any penalty charges as set forth in the
TCPL tariff governing the transportation of the gas sold hereunder, then all
such penalty charges actually incurred by Buyer with respect to such imbalance
shall be paid by Seller within fifteen (15) days after receipt of an invoice
therefor from Buyer.
15.3. If Seller fails to deliver the Daily Nomination pursuant to Article 5
hereof and is not otherwise excused from the obligation to deliver thereunder or
under any other term of this Contract, including force majeure, Seller agrees,
insofar as may be permitted under Seller's firm transportation service contract
with NOVA (the "NOVA Contract") and subject to the terms and conditions thereof
and the receipt of all necessary approvals from Canadian Regulatory Authorities,
to make available at Seller's cost, Seller's transportation rights under the
NOVA Contract only for that portion of such transportation service from the
Alberta Energy Company
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Station "C" ("AECO-C") to Empress Stn. No. 1958 known as NOVA Firm Service
Delivery at Empress (excluding for greater certainty NOVA Firm Service Receipt)
and only to the extent of any shortfall in delivery up to the Maximum Daily
Quantity and only for the duration of such shortfall; provided that Buyer pays
all the transportation commodity charges per 103m3 (or other applicable units of
measurement) payable by Seller for all such transportation rights of Seller as
well as any penalty charges as set forth in the NOVA tariff caused by an
over-delivery or under-delivery which can reasonably be considered to be the
fault of Buyer, and Seller shall pay all other costs and charges under the NOVA
Contract. Seller shall take such actions as Buyer may reasonably require to take
service under the NOVA Contract as contemplated hereunder (including, e.g.,
nominating service thereunder as requested by Buyer). Seller covenants and
agrees to maintain in effect a firm transportation service contract with NOVA
for delivery of the Maximum Daily Quantity to the Delivery Point for the primary
term of this Contract.
ARTICLE 16. FORCE MAJEURE
16.1 Neither Buyer nor Seller shall be liable in damages to the other for any
act, omission or circumstances occasioned by or in consequence of any event
constituting force majeure and the obligations of Seller and Buyer then existing
hereunder shall be excused during the period thereof to the extent affected by
such event of force majeure. The term "force majeure" shall mean any cause,
whether of the kind enumerated below or otherwise, and whether caused or
occasioned by or happening on account of the act or omission of one of the
parties hereto which affects obligations hereunder not within the control of the
party claiming excuse and which by the exercise of due diligence such party is
unable to prevent or overcome, including but not limited to acts of God,
strikes, lockouts, acts of the public enemy, criminal acts of trespassers, wars,
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blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes,
fires, storms, floods, washouts, arrests and restraints of rulers and peoples,
civil disturbances, explosions, breakages or accident to machinery or lines of
pipe, line freezeups, curtailments or prorationing by NOVA of firm service
contracts, temporary inability of TCPL due to an event of "force majeure" to
receive gas for Buyer's account, unscheduled outages which result in the
temporary inability of Buyer's Plant to utilize any portion of the Maximum Daily
Quantity, and the binding order or any court or governmental authority which has
been resisted in good faith by all reasonable legal means. A failure to settle
or prevent any strike or other controversy with employees or with anyone
purporting or seeking to represent employees shall not be considered to be a
matter within the control of the party claiming excuse. Under no circumstances
will lack of finances be construed to constitute force majeure.
16.2. Such causes or contingencies affecting the performance of this contract by
either party, however, shall not relieve it of liability in the event of its
concurring negligence or in the event of its failure to use due diligence to
remedy the situation and remove the cause in an adequate manner and with all
reasonable dispatch, nor shall causes or contingencies affecting the performance
of this Contract relieve either party from its obligations to make payments of
amounts then due hereunder nor shall such causes or contingencies relieve either
party of liability unless such party shall give notice and full particulars of
the same in writing or by telex to the other party as soon as possible after the
occurrence relied on.
16.3. In the event, as a result of force majeure, NOVA is rendered unable,
wholly or in part, to deliver to TCPL for Buyer's account the Maximum Daily
Quantity provided for herein on any day,
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then Seller shall use reasonable efforts to meet the Daily Nomination at the
Delivery Point; provided, however, that Seller shall not be obligated to curtail
firm customers in order to meet its reasonable efforts obligation.
16.4. Seller's obligation to sell and Buyer's right to purchase gas hereunder
shall be suspended during the effectiveness or any governmental action which
results in the interruption of deliveries or which prevents, totally or
partially, the exportation of gas from Canada, the importation of gas into the
United States by Buyer, or transportation of gas by TCPL and United States
Transporter for Buyer; provided, however, that where the exportation,
importation, use or transportation is only partially prevented by the
governmental action, Seller's and Buyer's obligations and rights hereunder shall
be suspended only to the extent prevented by such governmental action.
ARTICLE 17. LAWS AND REGULATORY BODIES
17.1 This Contract and the rights and obligations of the parties hereunder are
subject to all applicable present and future laws, rules, regulations and orders
of any regulatory or legislative body or other duly constituted authority having
jurisdiction over Seller or Buyer.
ARTICLE 18. TRANSFER AND ASSIGNMENT
18.1 Any company which shall succeed by purchase, merger, or consolidation of
the properties, substantially as an entirety, of Buyer or of Seller, as the case
may be, shall be entitled to the rights and shall be subject to the obligations
of its predecessor in title under this Contract. Seller may, without relieving
itself of its obligations under this Contract, assign any of its rights and
obligations hereunder to a corporation with which it is affiliated at the time
of such assignment.
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Otherwise no assignment of this Contract or any of its rights and obligations
hereunder shall be made by Seller without the written consent of Buyer first
obtained which consent shall not be unreasonably withheld. Buyer may, without
relieving itself of its obligations under this Contract, assign any of its
rights and obligations hereunder to a corporation with which it is affiliated at
the time of such assignment. Otherwise no assignment of this Contract or any of
its rights or obligations hereunder shall be made by Buyer without the written
consent of Seller first obtained which consent shall not be unreasonably
withheld. It is agreed, however, that the provisions of this Article 18 shall
not in any way prevent either party to this Contract from pledging or mortgaging
its rights hereunder as security for its indebtedness. In the event that a
person(s) with a security interest in this Contract succeeds to the rights of a
party by foreclosure or otherwise, the other party shall accord such successor
the same rights as its predecessor hereunder. This Contract shall be binding
upon and shall inure to the benefit of the respective successors and assigns of
the parties hereto.
ARTICLE 19. MISCELLANEOUS PROVISIONS
19.1 No waiver by Buyer or Seller of any default of the other under this
Contract shall operate as a waiver of a future default whether of a like or
different character.
19.2. The headings used throughout this Contract are inserted for reference
purposes only, and are to be considered or taken into account in construing the
terms or provisions of any Article or Section hereof nor to be deemed in any way
to qualify, modify or explain the effect of any such provisions or terms.
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19.3. Every notice, statement or bill provided for in this Contract shall be in
writing directed to the party to whom given, made or delivered at such party's
address as follows:
SELLER: Paramount Resources Ltd.
4000, 350 - 7th Avenue,S.W.
Calgary, Alberta
Canada, T2P 3W5
BUYER: Selkirk Cogen Partners, L.P.
c/o U.S. Generating Company
7500 Old Georgetown Road
Bethesda, Maryland 20814
Attn: Fuel Services
Selkirk Cogen Partners, L.P.
with a copy to: c/o U.S. Generating Company
One Bowdoin Square
Boston, Massachusetts 02114
Attn: Legal Group
Either party may change its address from time to time by giving written
notice of such change to the other party. Any notice, statement or bill or other
document made, given or delivered hereunder by mail shall be deemed to have been
effectively delivered to the addressee thereof at the end of the third (3rd)
business day after the date of mailing by prepaid registered mail in the United
States mail or Canadian mail; provided; that, at any time when there is a strike
affecting delivery of either United States mail or Canadian mail, all such
deliveries shall be made by hand or by telex. If any such notice, statement,
bill or other document is delivered by hand or by telex to an officer of the
addressee, it shall be deemed to have been received by the addressee as soon as
such delivery or transmission has been made to said officer.
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It is expressly understood and agreed, however, that the notices,
statements and bills referred to in this Contract hereof shall first be
delivered by telex, telecopier or the similar means, in accordance with the
dates and time provided in the applicable provisions of this Contract, and shall
be mailed as soon as practicable thereafter.
19.4 This Contract shall be construed in accordance with the laws of the
Province of Alberta.
19.5. This Contract amends and restates the Original Gas Purchase
Contract effective the Effective Date.
19.6. The rights and remedies of Buyer and Seller under this Contract are
cumulative and in addition to any other rights and remedies that Buyer and
Seller may have at law or in equity.
19.7. The liabilities of Buyer and Seller for breach of any covenants,
representations or warranties and the obligations of Buyer and Seller under any
indemnity contained in this Contract shall survive termination of this Contract
except as otherwise expressly provided.
19.8. Notwithstanding any provision of this Contract, nothing herein shall be
construed as prohibiting Buyer from utilizing any gas purchased from Seller for
any other lawful purpose.
19.9. Pursuant to the Original Gas Purchase Contract, Seller has executed and
delivered to TCPL a Guarantee, a copy of which is appended as Exhibit "B"
hereto, and Buyer has executed and delivered to Seller an Indemnity, a copy of
which is appended as Exhibit "C" hereto, which Guarantee and Indemnity, each as
amended, shall continue in full force and effect, as and from the Effective
Date.
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ARTICLE 20. ARBITRATION
20.1 In the event that either party has the right to require a matter to be
submitted to arbitration pursuant to this contract the arbitration shall be
conducted in accordance with the UNCITRAL Arbitration Rules pursuant to the
British Columbia International Commercial Arbitration Act.
20.2. The arbitrators selected to act hereunder shall be qualified by education
and training to pass up on the particular question in dispute, and shall be
disinterested persons. Therefore, it is agreed that if an engineering question
is involved, qualified engineers shall be appointed, and similar procedure will
be followed in connection with other questions.
20.3. The arbitrators so chosen (the "Board") shall proceed immediately to hear
and determine the question or questions in dispute. The decision of the
arbitrators, or a majority of them, shall be made within forty-five (45) days
after appointment of the single arbitrator or third arbitrator, as the case may
be, subject to any reasonable delay due to unforeseen circumstances.
20.4. The decision of the arbitrator or arbitrators shall be in writing and
signed by the arbitrator or arbitrators and shall be final and binding upon the
parties as the question or questions submitted for determination. It is the
intention of the parties that such decision shall not be subject to court
review; however, such decision shall be enforceable through judicial
proceedings. The written decision of the Board of a majority thereof may be
issued with or without an opinion. If any party requests a written opinion with
regard to a decision, one shall be issued expeditiously, but its issuance shall
not delay compliance with and implementation of the Board's or majority's
decision.
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20.5. Pending the outcome of any such arbitration, the terms in effect
immediately prior to such arbitration shall remain in effect. Any modification
approved by the Board shall be effective prospectively only, and such
modification shall become effective on the first day of the month following the
decision of the arbitrator or arbitrators, subject, however, to the next two
sentences hereof. Actions taken pursuant to this Article 20 shall be subject to
the receipt of all governmental and regulatory approvals required to make such
actions effective without modifications (unless such modifications are
acceptable to both parties); the parties shall promptly apply for such
approvals.
20.6. Each party shall bear the cost of the arbitrator appointed by it and both
parties agree to share equally all costs and expenses of the third arbitrator
and all common costs.
ARTICLE 21. NONRECOURSE OBLIGATION OF JOINT VENTURE
21.1 Seller acknowledges and agrees that: (a) Buyer is a Limited Partnership;
(b) Seller shall have no recourse against any participant in Buyer with respect
to the obligations of Buyer and its sole recourse shall be against the Limited
Partnership assets, irrespective of any failure to comply with applicable law or
any provisions of this Contract; (c) no claim shall be made against any
participant in Buyer in connection with the obligations of Buyer under this
Contract, except that the participants may be joined as nominal parties for the
purpose of enforcing Seller's rights hereunder; (d) Seller shall have no right
to any claim in respect of Buyer not yet due and owing; and (e) this
representation is made expressly for the benefit of the participants in Buyer.
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ARTICLE 22. MATERIAL BREACH; REMEDIES
22.1 If Seller fails to deliver a Report when due pursuant to Section 14.1,
Buyer may withhold all or any part of the Sum (as defined in Section 8.1), and
no interest shall accrue thereon, until such time as Seller has delivered the
overdue Report. Seller shall continue to perform its obligations under this
Contract during any period in which Buyer is withholding all or any part of the
Sum as provided in the preceding sentence.
22.2. Each of the following events shall constitute a "material breach" by
Seller of this Contract: (a) the failure to obtain and maintain a Minimum
Removal Permit as required by Section 6.3.a, subject to the cure provisions
contained therein; (b) Third Party Sales and/or Excess Third Party Sales not
permitted pursuant to Sections 13.5.a. or 13.5.b. respectively; (c) Seller's
failure to cure a Deficiency as required pursuant to Article 14 of this
Contract; and (d) Seller's failure to post, maintain, or renew a letter of
credit as required pursuant to Section 14.11 (a "Letter of Credit Default"),
subject to Section 22.4.
Upon a material breach as set forth in the preceding sentence, Seller and
Buyer agree that, notwithstanding any other provision of this Contract, Buyer
shall have the following rights and remedies, which rights and remedies are
cumulative and not exclusive of any rights or remedies which Buyer may otherwise
have under this Contract or at law or in equity (unless otherwise specifically
stated herein):
22.2.a. Buyer may terminate this Contract upon thirty (30) days written
notice to Seller. Upon termination of this Contract, Buyer shall have the gas
substitution rights set forth in Section 14.7 and Seller shall have the
obligations set forth in Section 14.8. Seller shall indemnify
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Buyer, by means of a lump sum payment made within 180 days of the termination of
this Contract, for the costs, expenses and charges recoverable by Buyer under
Section 14.8.
22.2.b. Buyer may reduce the Maximum Daily Quantity to any amount including
zero and Buyer shall have the gas substitution rights set forth in Section 14.7
of this Contract and Seller shall have the obligations set forth in Section
14.8. Buyer shall give Seller written notice of any such reduction in the
Maximum Daily Quantity and the effective date of such reduction, such date to be
no earlier than the first (1st) day after the expiration of the Cure Period or
the thirtieth (30th) day after the date of Buyer's notice, whichever is later.
Upon Buyer's exercise of its right under this Section 22.2.b, Buyer shall have
no further remedies for the material breach which gave rise to such reduction in
the Maximum Daily Quantity, unless such material breach continues after the date
of the notice of the reduction of the Maximum Daily Quantity pursuant hereto.
22.2.c. Seller shall not make any Third Party Sales without the prior
written consent of Buyer, unless this Contract provides for a cure of the
material breach and Seller has cured such breach in the manner required by this
Contract.
22.2.d. Buyer may unilaterally take such action before any United States or
Canadian Regulatory Authority as Buyer shall deem necessary or appropriate to
secure the full performance of this Contract or to change, alter or vary any
application, permit or license issued in connection with the gas to be delivered
under this Contract; provided, however, that Seller does not hereby waive any
right to contest such action.
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22.2.e. Seller shall not remove any portion of Seller's Lands pursuant to
Section 14.9, unless this Contract provides for a cure of the material breach
and Seller has cured such breach in the manner required by this Contract.
22.3 Buyer shall provide Seller with fifteen (15) days advance written notice
prior to its exercise of any of the aforementioned remedies upon a Letter of
Credit Default and, upon Seller's delivery of a letter of credit which satisfies
the requirements of Section 14.11 of this Contract within the said fifteen (15)
days, such Letter of Credit Default shall be deemed to be cured.
22.4. The events identified in Section 22.2 as material breaches are not the
exclusive events which may constitute a material breach under this Contract.
Upon the occurrence of a material breach not identified in section 22.2 or upon
the occurrence of any other breach of this Contract, and except as is otherwise
provided in this contract the non-breaching party shall be entitled to exercise
all rights and remedies it may have at law or in equity and no single or partial
exercise of any right or remedy shall preclude any other or further exercise of
any right or remedy at law or in equity. The respective liabilities of Buyer and
Seller hereunder for breach of any covenants, representations or warranties and
the respective obligations of Buyer and Seller under any indemnity herein
contained, including any payments required pursuant to Section 8.3 and Section
22.7, shall survive termination of this Agreement, except as otherwise herein
expressly provided.
22.5. A party may withhold payments due the other party under this Contract to
offset damages, costs and expenses reasonably incurred by the withholding party
as a result of a material breach of this Contract by such other party.
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22.6. Any party which is found pursuant to a final judicial determination to be
in breach of its obligations under this Contract shall be liable to the other
party for all costs and expenses, including reasonable attorneys fees in respect
of such breach, incurred by the non-breaching party in enforcing its rights
under this Contract.
22.7. No failure or delay on the part of a party in exercising any right
hereunder and no course of dealing between the parties which does not constitute
an agreement in writing between the parties shall operate as a waiver thereof.
No waiver by a party of any breach or default of the other party under this
Contract shall operate as a waiver of a future default whether of a like or
different character.
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IN WITNESS WHEREOF the parties hereto have caused this Second Amended and
Restated Gas Purchase Contract to be executed in duplicates and have caused
their corporate seal to be hereunto affixed, attested by the hands of their
proper officers duly authorized in that behalf as of the day and year first
above written.
SELKIRK COGEN PARTNERS, L.P.
By: JMC SELKIRK, INC.
Managing General Partner
By: /s/ George J. Grunbeck
-----------------------------------
Name: George J. Grunbeck
Title: Vice President
PARAMOUNT RESOURCES LTD.
Per: /s/ James H. T. Riddell
----------------------------------
Name: James H. T. Riddell
Title: Corporate Operating Officer
Per: /s/ Laurel A. Friesen
----------------------------------
Name: Laurel A. Friesen
Title: Assistant Corporate Secretary
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AMENDING AGREEMENT
THIS AMENDING AGREEMENT, made as of the 20th day of July, 1998.
BETWEEN: TRANSCANADA PIPELINES LIMITED
a Canadian corporation
("TransCanada")
OF THE FIRST PART
AND: SELKIRK COGEN PARTNERS, L.P.
a company incorporated under the laws of
the State of Delaware
("Shipper")
OF THE SECOND PART
WITNESSES THAT:
WHEREAS TransCanada and Shipper are parties to a contract for firm
transportation service to the Iroquois delivery point made as of the 6th day of
September, 1991, as amended, identified in TransCanada's records as Contract No.
2132 and having a current Contract Demand of 594.9 103m3 per day, (hereinafter
called the "Contract"); and
WHEREAS Shipper has requested, and TransCanada has agreed to a decrease of
170.0 103m3 per day in the Contract Demand of the Contract, concurrent with
Paramount Resources Ltd. ("Paramount") accepting a new volume of 170.0 103m3 per
day under a separate firm service transportation contract of even date herewith
pursuant to an assignment of that capacity from Shipper to Paramount (the
"Permanent Assignment") under a permanent assignment agreement of even date
herewith (the "Permanent Assignment Agreement").
NOW THEREFORE THIS AGREEMENT WITNESSES THAT, in consideration of the
covenants and agreements herein set forth, the parties hereto covenant and agree
as follows:
1. Clause 2.1 of the Contract shall be and is hereby amended by replacing the
number "594.9" wherever this number appears with the number "424.9".
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2. The Contract as herein modified is hereby ratified and confirmed.
3. This Amending Agreement and the rights and obligations of the parties
hereunder are subject to all valid and applicable present and future laws,
rules, regulations, and orders of any regulatory or legislative authority having
jurisdiction or control over TransCanada's Transportation Tariff (including
without limitation the FT Toll Schedule), and the Contract as herein amended and
the assignment or sub-assignment of the service entitlement thereunder.
4. This Amending Agreement shall be construed in accordance with and governed by
the laws of the Province of Alberta, and, when applicable, the laws of Canada.
5. All terms and conditions herein capitalized and not otherwise defined in this
Amending Agreement are incorporated by reference into this Amending Agreement
from the FT Toll Schedule, the List of Tolls, and the General Terms and
Conditions set out in TransCanada's Transportation Tariff as amended or approved
from time to time by the National Energy Board.
6. This Amending Agreement shall inure to the benefit of and be binding upon the
parties hereto and their respective successors and permitted assigns.
7. This Amending Agreement shall be effective the later of (a) the 1st day of
November, 1998, or (b) the Effective Date as defined in Paragraph 3 of the
Permanent Assignment Agreement; provided that this Amending Agreement shall be
deemed null and void if the Permanent Assignment does not become effective in
accordance with the terms of the Permanent Assignment Agreement.
- --------------------------------------------------------------------------------
Sheet No. 2
<PAGE>
t
- --------------------------------------------------------------------------------
IN WITNESS WHEREOF, the parties hereto have executed this Contract as of
the date first above written.
SELKIRK COGEN PARTNERS, L.P.: TRANSCANADA PIPELINES LIMITED:
by: JMC Selkirk, Inc., Managing
General Partner
/s/George J. Grunbeck /s/Greg Fisher
- ---------------------------------- -------------------------------
(Signed) (Signed)
George J. Grunbeck Greg Fisher
- ---------------------------------- -------------------------------
(Print Name) (Print Name)
Vice President Vice President
- --------------------------------- -------------------------------
(Title) (Title)
TRANSCANADA PIPELINES LIMITED:
/s/ Max Feldman
-------------------------------
(Signed)
Max Feldman
--------------------------------
(Print Name)
VP Customer Service
--------------------------------
(Title)
Contract Approval
Portfolio Team Review X
--------
Legal Review --------
SELKIRK COGEN PARTNERS, L.P.
SELKIRK COGEN PARTNERS, L.P.
OFFICER'S CERTIFICATE
August 31, 1998
Bankers Trust Company,
as Trustee
Corporate Trust Department
4 Albany Street
New York, New York 10006
Ladies and Gentlemen:
This Officer's Certificate is being delivered by the undersigned, Selkirk
Cogen Partners, L.P., a Delaware limited partnership (the "Partnership"),
pursuant to Section 6.20 of the Trust Indenture dated as of May 1, 1994 among
the Partnership, Selkirk Cogen Funding Corporation and Bankers Trust Company, as
Trustee (the "Indenture").
The Partnership has entered into the following transactions, which
collectively are referred to in this Officer's Certificate as the "Unit l
Restructuring": (1) the restructuring of the NIMO Power Purchase Agreement
between the Partnership and NIMO pursuant to the Master Restructuring Agreement
dated as of July 9, 1997 among NIMO, the Partnership and other IPP's, as
amended, (2) the execution, delivery and performance of the agreements listed on
Exhibit A to this Officer's Certificate, and (3) the completion of the other
transactions listed on Exhibit A. Capitalized terms used and not defined herein
shall have the meanings assigned to such terms in Exhibit A and in the
Indenture.
The Partnership hereby certifies to you as follows:
1. The undersigned officer of JMC Selkirk, Inc., the Managing General Partner,
is its Authorized Representative, has read the provisions of Section 6.20
and related definitions of the Indenture and has reviewed the documents
which comprise the Unit 1 Restructuring and made such other examination or
investigation as is necessary to enable the Partnership to express an
informed opinion as to the matters addressed by this Officer's Certificate.
2. The implementation of the Unit 1 Restructuring, including (a) the
execution, delivery and performance of the Amended and Restated NIMO Power
Purchase Agreement, the Amended Paramount Contract and the Amended
TransCanada Agreement, and the termination of the NIMO License Agreement,
could not reasonably be expected to result in a Material Adverse Change. As
required by Section 6.20(a)(i) of the Indenture, the foregoing
determination is concurred with by the Independent Engineer in the
Independent Engineer's Certificate addressed to you and dated August 31,
1998, executed by R.W. Beck, Inc. (the "Independent Engineer's
Certificate") and, with respect to the Amended
24 Power Park Drive, Selkirk, New York 12158-2299
Telephone (518) 475-5773 Telefax (518) 475-5199
<PAGE>
SC
Paramount Contract and the Amended TransCanada Agreement, by the Gas
Consultant in the Gas Consultant's Certificate addressed to you and dated
August 28, 1998, executed by C.C. Pace Resources (the "Gas Consultant's
Certificate").
3. After giving effect to the implementation of the Unit 1 Restructuring,
including the execution, delivery and performance of the Amended and
Restated NIMO Power Purchase Agreement, the Amended Paramount Contract and
the Amended TransCanada Agreement, and the termination of the NIMO License
Agreement, the minimum annual Projected Debt Service Coverage Ratio will be
equal to or exceed 1.5:1 and the average annual Projected Debt Service
Coverage Ratio for the remaining term of the Bonds will be equal to or
exceed 1.75:1. As required by Section 6.20(a)(ii) of the Indenture, the
foregoing determination is concurred with in the Independent Engineer's
Certificate. The full calculation of the Projected Debt Service Coverage
Ratio (together with supporting documentation) is set forth in Attachment B
to the Independent Engineer's Certificate.
4. The Partnership's entering into the Additional Contracts listed on Exhibit
A could not reasonably be expected to result in a Material Adverse Change
and would not impair the ability of the Partnership to perform its
obligations under the other Project Agreements. As required by Section
6.20(c)(i) of the Indenture, the foregoing determination is concurred with
in the Independent Engineer's Certificate and, to the extent such matters
relate to the Partnership's fuel supply, in the Gas Consultant's
Certificate.
5. The Partnership will be furnishing to the Collateral Agent the Ancillary
Documents related to the Additional Contracts listed on Exhibit A within a
reasonable period, to the extent required under Section 6.20(c)(i)(B) of
the Indenture. The Partnership was unable to obtain a Consent or Opinion of
Counsel with respect to the other IPP parties to the MRA or to the
Allocation Agreement using commercially reasonable efforts, due to the
large number of Persons involved.
6. With respect to each of the transactions which comprise the Unit 1
Restructuring, the Partnership has complied with the covenants set forth in
Section 6.20 of the Indenture, and no Event of Default under this Indenture
has occurred and is continuing.
2
<PAGE>
SC
IN WITNESS WHEREOF, the undersigned has executed this Officer's Certificate
as of the date first written above.
SELKIRK COGEN PARTNERS, L.P.
By: JMC SELKIRK, INC.,
its Managing General Partner
By: /s/John R. Cooper
---------------------------
Name: John R. Cooper
Title: Vice-President
3
<PAGE>
SC
EXHIBIT A
RESTRUCTURING DOCUMENTS
1. Master Restructuring Agreement dated as of July 9, 1997 among Niagara
Mohawk Power Corporation ("NIMO"), Selkirk Cogen Partners, L.P. (the
"Partnership") and the other IPP's named therein (as amended, the "MRA")
a. First Amendment dated March 31, 1998
b. Second Amendment dated April 21, 1998
c. Third Amendment dated April 30, 1998
d. Fourth Amendment dated May 7, 1998
e. Fifth Amendment dated June 2, 1998
2. Allocation Agreement dated April 21, 1998 among the Partnership and certain
other IPP's (as amended, the "Allocation Agreement")
a. First Amendment dated May 7, 1998
3. Amended and Restated Power Purchase Agreement dated as of July 1, 1998
between the Partnership and NIMO (the "Amended and Restated NIMO Power
Purchase Agreement")
4. Mutual General Release and Agreement dated as of July 1, 1998 between the
Partnership and NIMO (the "Mutual Release")
5. Second Amended and Restated Gas Contract dated May 6, 1998 between the
Partnership and Paramount Resources Limited ("Paramount") (the "Amended
Paramount Contract")
6. Agreement with respect to Gas Transportation dated as of May 6, 1998
between the Partnership and Paramount (the "Paramount Transportation
Agreement")
7. Amendment to Gas Transportation Agreement dated as of July 20, 1998 between
the Partnership and TransCanada Pipelines Ltd. ("TransCanada") (the
"Amended TransCanada Agreement")
8. Three-party agreement with respect to Items 6 and 7 above dated as of July
20, 1998 among the Partnership, Paramount and TransCanada (the "TransCanada
Consent")
9. The Partnership's agreement with NIMO (contained in the Mutual Release) to
terminate the existing License Agreement dated as of October 23, 1992
between the Partnership and NIMO (the "License Agreement")
RW Beck
INDEPENDENT ENGINEER'S CERTIFICATE
August 31, 1998
Bankers Trust Company,
as Trustee
Corporate Trust Department
4 Albany Street
New York, New York 10006
Re: Results of Independent Engineer's Review
Restructuring of Phase I
Selkirk Cogeneration Facility
Ladies and Gentlemen:
In our capacity as Independent Engineer under the Indenture (defined below) we
have performed a review of the impact of the Phase I Restructuring (defined
below) on the Selkirk Project projected economics. For purposes of this
Independent Engineer's Certificate "Phase I Restructuring" means and includes
the following transactions: (1) the restructuring of the current Phase I power
purchase agreement ("Existing PPA") between Selkirk Cogen Partners, L.P. (the
"Partnership") and Niagara Mohawk Power Corporation ("NiMo") pursuant to the
Master Restructuring Agreement dated as of July 9, 1997 among NiMo, the
Partnership and other IPP's, as amended, (2) the execution, delivery and
performance of the agreements listed on Attachment A to this Independent
Engineer's Certificate, and (3) the completion of the other transactions listed
on Attachment A. Capitalized terms used and not defined herein shall have the
meanings assigned to such terms in Attachment A and in the Trust Indenture dated
as of May 1, 1994 among Selkirk Cogen Funding Corporation, the Partnership and
Bankers Trust Company, as Trustee (the "Indenture").
R. W. Beck, Inc., the Independent Engineer under the Indenture, hereby certifies
to you as follows:
1. The undersigned officer of R. W. Beck, Inc. is its Authorized
Representative, has read the provisions of Sections 6.20(a)(i) and
(ii) and 6.20(c)(i) and related definitions of the Indenture and
has made such examination or investigation as is necessary to
enable the expression of an informed opinion as to the matters
addressed by this Independent Engineer's Certificate.
The Corporate Center, East Wing 550 Cochituate Road P.O. Box 9344 Framingham,
MA 01701-9344
Phone (508) 935-1600 Consulting Fax (508) 935-1888 Engineering Fax (508)
935-1666
<PAGE>
Independent Engineer's Certificate
August 31, 1998
Page 2
2. Our analyses focused on the preparation and comparison of
projected economics through the terms of the bonds for the case
with the Existing PPA and the case that would result from the
proposed Phase I Restructuring. For both cases, projected
economics were prepared utilizing the Selkirk Cogen Partner's
Long-Term Production Model which is the model used in the
preparation of the Annual Independent Engineer's Report delivered
to the Trustee under the Indenture. However, the Annual
Independent Engineer's Reports are prepared utilizing a
short-term (i.e., monthly) model for the first two years, which
was not necessary as part of these analyses. Further, as part of
our analyses, the projected economics presented in the Annual
Independent Engineer's Report dated November 1997 (i.e., with the
Existing PPA), were updated to reflect recent and proposed
assumptions by the Partnership. The resultant case with the
Existing PPA is referred to herein as the "Existing PPA Case."
The projected economics for the Phase I Restructuring (the
"Amended PPA Case") include modeling the impact of the proposed
Amended PPA, as well as the resultant changes to projected
electric dispatch and operating expenses.
We have not reviewed the Selkirk Project Agreements for gas
supply and transportation including those Phase I Restructuring
agreements indicated as numbers 5, 6, 7, and 8 on Attachment A,
but have relied upon the review of the fuel agreements and
projections of the Selkirk Cogeneration Facility fuel costs as
reviewed by the Gas Consultant, C. C. Pace. The details of our
comparative analyses are described in Attachment B to this
letter.
3. We believe that the projected economics for the two cases use
reasonable assumptions consistent in all material respects with
the Selkirk Project Agreements and the historical operating
results of the project, and that the resultant Projected Debt
Service Coverage Ratios are reasonable in light of such
assumptions.
4. Subject to the foregoing and Attachment B, we have made the
following determinations:
. We find, and concur with the Partnership's determination
pursuant to Section 6.20(a)(i) and (c)(i) of the Indenture set
forth in Attachment C, that the implementation of the Phase I
Restructuring could not reasonably be expected to result in a
"Material Adverse Change" within the meaning of the
Partnership's Indenture and, to the extent applicable, would
not impair the ability of the Partnership to perform its
obligations under the other Project Agreements.
. We find, and concur with the Partnership's determination
pursuant to Section 6.20(a)(ii) of the Indenture set forth in
Attachment C, that, after giving effect to the Phase I
Restructuring, the debt service coverage thresholds
established in the Indenture are satisfied -- a minimum annual
<PAGE>
Independent Engineer's Certificate
August 31, 1998
Page 3
Projected Debt Service Coverage Ratio of at least 1.5:1 and an
average annual Projected Debt Service Coverage Ratio for the
remaining term of the Bonds of at least 1.75:1.
IN WITNESS WHEREOF, the undersigned has executed this Independent Engineer's
Certificate as of the date first written above.
R. W. BECK, Inc.
By: /s/Michael W. Noga
------------------------------------
Name: Michael W. Noga
Title: Principal and Senior Director
<PAGE>
ATTACHMENT A
RESTRUCTURING DOCUMENTS
1. Master Restructuring Agreement dated as of July 9, 1997 among Niagara
Mohawk Power Corporation ("NiMo"), Selkirk Cogen Partners, L.P. (the
"Partnership") and the other IPP's named therein (as amended, the "MRA")
a. First Amendment dated March 31, 1998
b. Second Amendment dated April 21, 1998
c. Third Amendment dated April 30, 1998
d. Fourth Amendment dated May 7, 1998
e. Fifth Amendment dated June 2, 1998
2. Allocation Agreement dated April 21, 1998 among the Partnership and certain
other IPP's (as amended, the "Allocation Agreement")
a. First Amendment dated May 7, 1998.
3. Amended and Restated Power Purchase Agreement dated as of July 1, 1998
between the Partnership and NiMo (the "Amended PPA")
4. Mutual General Release and Agreement dated as of July 1, 1998 between the
Partnership and NiMo (the "Mutual Release")
5. Second Amended and Restated Gas Contract dated May 6, 1998 between the
Partnership and Paramount Resources Limited ("Paramount") (the "Amended
Paramount Contract")
6. Agreement with respect to Gas Transportation dated May 6, 1998 between the
Partnership and Paramount (the "Paramount Transportation Agreement").
7. Amendment to Gas Transportation agreement dated July 20, 1998 between the
Partnership and TransCanada Pipelines Ltd. ("TransCanada") (the "Amended
TransCanada Agreement")
8. Three-party agreement with respect to Items 6 and 7 above dated July 20,
1998 among the Partnership, Paramount and TransCanada (the "TransCanada
Consent")
9. The Partnership's agreement with NiMo (contained in the Mutual Release) to
terminate the existing License Agreement dated as of October 23, 1992
between the Partnership and NiMo (the "License Agreement")
<PAGE>
ATTACHMENT B
Following is a summary of the detailed analyses utilized in preparing the
Existing PPA Case and the Amended PPA Case. Also attached are Pro Forma
summaries for each of the cases.
EXISTING PPA CASE
The Existing PPA Case is based on the assumption that the overall NiMo
restructuring represented by the Master Restructuring Agreement among NiMo and
certain IPP's (the "MRA") is not implemented. Further, the Existing PPA case was
prepared in order to reflect the Partnership's updated assumptions in operation
and pricing conditions for each of Phases I and II from that which was projected
and included in our November 1997 Independent Engineers Report (the "IER"). The
changes between the IER conditions and assumptions include the following items:
(1) a reduction in the O&M Fee after year 2000; (2) an increase in the steam
demand from GE; (3) Phase I gas capacity release through the term of the Bonds;
(4) additional gas peak shaving for Phase I; (5) additional gas transportation
revenue, and; (6) changes in the Iroquois transportation demand and
transportation commodity costs for Phase I and Phase II. The assumptions related
to gas were reviewed and concurred with by C.C. Pace, the Fuel Consultant.
Basic assumptions used in the Projected Operating Results, including
availability, fuel pricing, and dispatch reflect assumptions commensurate with
long-term projections.
AMENDED PPA CASE
The July 29, 1998 draft of the Amended and Restated Power Purchase Agreement
between NiMo and the Partnership (the "Amended PPA") provides for the project
term to be reduced to 10 years from June 30, 1998. The Existing PPA is set to
expire on April 16, 2012. Under the terms of the Amended PPA that contract will
expire on June 30, 2008.
The Amended PPA provides for revenues to be compressed into a shorter term and
includes a monthly contract payment ("Monthly Contract Payment"), the fixed
portion of which is payable by NiMo, regardless of the operation of Phase I. The
variable portion of the Monthly Contract Payment is based on energy and capacity
actually sold to NiMo under the Amended PPA. The Monthly Contract Payment
consists of four indexed pricing components; the capacity component and the
fixed portion of the energy component are offset by actual market prices. Market
prices will be established by the marketplace in conjunction with the
Independent System Operator and/or Power Exchange ("ISO/PE") for each of 11
regions within New York State. 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. Prior to the establishment of such market prices, the initial market
pricing for energy will be a proxy market price based on NiMo's tariff for power
purchases from QF's.
The Amended PPA also provides that the Selkirk project may require NiMo to take
and purchase defined quantities of energy and capacity, at market prices, during
the period before the ISO/PE is fully functional. This energy and capacity may
be produced by Phase I, Phase II or third party sources. NiMo also has the right
to call Phase I's energy and capacity, up to the defined contract quantities,
during the period prior to the
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 2
implementation by the ISO/PE of market pricing (or 24 months, if earlier). If
NiMo exercises this right, the purchase price will be the greater of the initial
market price or the project's variable costs of production.
As a result of the MRA many of the power purchase agreements which NiMo has with
NUGs will be restructured or bought out. Therefore, the level of dispatch of the
remaining units including Selkirk Phase I and Phase II will be modified. The
Partnership has provided a dispatch analysis conducted by Slater Consulting
which models the dispatch of Selkirk's Phases I and II after the restructuring
in New York State. Dispatch factors increased from that assumed in the Existing
PPA Case, principally due to the retirement of approximately 1,050 MW of
existing NUG units. Slater's analysis also includes a market price for
electricity after restructuring which is the projected price for electricity for
the region in which the Selkirk facility is located. The "Market Price"
projected by Slater has been used in pricing both the fixed and variable
portions of the energy component of the monthly contract payment.
The higher dispatch projections for Selkirk Phase I and II will result in a
change in the schedule of major maintenance expenditures; therefore, we have
estimated a revised schedule of major maintenance deposits.
We believe that the non-fuel operating and maintenance expenses for the Amended
PPA Case will not increase materially over those for the Existing PPA Case, and
therefore have not revised their costs for the Amended PPA Case. We examined the
impact of a marginal increase to normal non-fuel operating and maintenance
expenses and find that it has little impact on the debt service coverage ratio
for the Amended PPA Case.
REVENUES
The Amended PPA provides the Partnership three potential sources of revenue. The
first revenue source will be Monthly Contract Payments to be paid by NiMo
regardless of Phase I output, except in the event that the Market Price or
Market Capacity Price (which offset the capacity component and the fixed portion
of the energy component) are so high as to reduce the Monthly Contract Payment
below zero. In such case the Partnership would be obligated to make payments to
NiMo.
The Partnership has two options for augmenting the fixed portions of the Monthly
Contract Payment: (1) it can exercise its option, prior to the establishment of
a fully functioning ISO/PE to require NiMo to take and purchase up to the
contract quantity of energy or capacity, at the Market Energy Price ("Sale
Option"); and (2) in lieu of or in addition to sales to Nimo, it can make market
sales of Phase I energy or capacity. In 1998 there is an additional one-time
adjustment which represents revenue to Selkirk in 1998 only. A new set of
inputs, as described below, exists in the model which addresses the changed
revenue structure as proposed in the Amended PPA.
Contract Quantities. The Annual Contract Volumes in MWh, which are used to
calculate the fixed portions of the Monthly Contract Payment and establish the
maximum quantities
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 3
of energy and capacity which NiMo can be obligated to purchase or Selkirk
obligated to sell, are as shown in Table 1. The Amended PPA specifies applicable
monthly quantities (the "Monthly Contract Quantity") based on the Annual
Contract Volumes.
Table 1
Annual Contract Volume (MWh)
Contract Year Annual Contract Volume (MWh)
-------------- ----------------------------
1 325,400
2 331,000
3 375,900
4 417,500
5 419,500
6 442,000
7 451,700
8 461,300
9 473,400
10 485,200
.
MONTHLY CONTRACT PAYMENTS The Monthly Contract Payment is the sum of four (4)
components: (1) a Capacity Payment; (2) an Energy Payment; (3) a Transportation
Payment; and (4) an Operation and Maintenance Payment. NiMo will be obligated to
pay the Partnership the monthly payment to the extent such number is positive,
and the Partnership will be obligated to pay NiMo the monthly payment to the
extent such number is negative. In the Amended PPA Case, this number is always
positive.
1. The "Capacity Payment" will be an amount equal to the difference between
(A) the Contract Capacity Payment and (B) the Market Capacity Payment.
A. The "Contract Capacity Payment" will equal the product of (i) the
Contract Capacity Rate, (ii) the Monthly Contract Quantity and (iii)
the DMNC Adjustment. The Contract Capacity Rates are as follows:
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 4
Contract Year Capacity Rate
1 $73.83/MWh
2 $73.60/MWh
3 $75.73/MWh
4 $75.76/MWh
5 $76.10/MWh
6 $76.45/MWh
7 $76.82/MWh
8 $77.23/MWh
9 $77.79/MWh
10 $78.42/MWh
The DMNC Adjustment is a quotient, the numerator of which is the tested
Phase I DMNC and the denominator of which is 79.9 MW.
B. The "Market Capacity Payment" will be an amount equal to the
product of (x) the Market Capacity Price in $/MW and (y) the
weighted averaged capacity associated with the notional quantity
of capacity corresponding to the applicable contract quantity.
The Market Capacity Price will be: (i) equal to zero during the
period prior to the establishment of the ISO/PE and any time
thereafter when no separate capacity market exists; and (ii)
after the ISO/PE is established and only if a separate capacity
market exists, equal to the market price paid to sellers for
capacity at the project's location.
2. The "Energy Payment" will be equal to the sum of (A) the Contract Energy
Payment, (B) the Delivered Energy Payment, (C) the Delivered Capacity
Payment and (D) the Call Energy Payment.
A. The "Contract Energy Payment" will be an amount equal to the product
of (i) the difference between the Contract Energy Price and the Market
Energy Price, (ii) the Monthly Contract Quantity and (iii) the DMNC
Adjustment. The Contract Energy Price for the first two Contract Years
will be fixed as follows: $15.80/MWh for the first contract year and
$15.95/MWh for the second contract year. In contract years 3 through
10, the Contract Energy Price will consist of the heat rate of 10,950
MMBtu/MWh multiplied by 105% of the current month's spot gas price at
the Empress border. This spot gas price is currently assumed to be
equal to the Pan Can Commodity Negotiated T2 rate, times 10,950 MMBtu
per MWh and is estimated by the Partnership to be $18.25 per MWh in
year 3 and $19.70 per MWh in year 4.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 5
The Market Energy Price is defined as the locational based market
price ("LBMP") for energy for the next day which is applicable to the
Selkirk Project. Prior to the establishment of the ISO/PE and its
implementation of LBMP pricing, the Market Energy Price will be NiMo's
short-term avoided energy and capacity costs, as stated in its tariff
for the purchase of power from QF's ("SC-6 Rate").
B. The "Delivered Energy Payment" will be an amount equal to the product
of (i) the Delivered Energy Quantity (which is the amount of energy
actually sold to NiMo) and (ii) the Market Energy Price.
C. The "Delivered Capacity Payment" will be equal to the product of (i)
the Delivered Capacity Quantity (which is the amount of capacity
actually sold to NiMo) and (ii) the Market Capacity Price in $/MW.
D. The "Call Energy Payment" will be equal to the product of (i) the
Delivered Call Quantity (which is the amount of energy actually sold
to NiMo in connection with its exercise of the Call Option) and (ii)
the Call Energy Price in $/MW. The Call Energy Price will be the
higher of the SC-6 rate and the project's variable fuel and operation
and maintenance cost of production.
3. The "Transportation Payment" will be an amount equal to the product of (A)
the Transportation Price, (B) the Monthly Contract Quantity and (C) the
DMNC Adjustment. The Transportation Price for the first two contract years
is fixed; it will be $7.15/MWh in the first contract year and $7.35/MWh in
the second. Beginning on July 1 of the year 2000 and thereafter, the
Transportation Price will be equal to $7.15/MWh adjusted to reflect changes
since July 1, 1998 in the consumer price index for urban consumers in New
York-Northern New Jersey-Long Island ("CPI").
4. The "Operation and Maintenance Payment" will be the product of (A) the O&M
Price, (B) the Monthly Contract Quantity and (C) the DMNC Adjustment. The
O&M Price for the first two contract years will be fixed as $6.70/MWh in
the first contract year and $6.89/MWh in the second contract year.
Beginning on July 1 of the year 2000 and continuing thereafter, the O&M
Price will be $6.70/MWh adjusted to reflect changes since July 1, 1998 in
CPI. For purposes of this report we have assumed that the rate of general
inflation is the same as contained in the Existing PPA Case, which is 3.1
percent per year.
The pricing components are summarized for each of the first five years of the
Amended PPA in Table 2.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 6
<TABLE>
<CAPTION>
Table 2
Fixed Contract Price ($/MWh)
<S> <C> <C> <C> <C> <C>
Contract Contract Contract Contract Contract Total
Year Capacity Rate Energy Price Transportation Price O&M Price FCP
---- ------------- ------------ -------------------- --------- ---
1 73.83 15.80 7.15 6.70 103.48
2 73.60 15.95 7.35 6.89 103.79
3 75.73 18.25 7.60 7.12 108.70
4 75.76 19.70 7.84 7.34 110.63
5 76.10 22.80 8.08 7.57 114.55
</TABLE>
For purposes of this analysis, we have utilized the Slater forecast of the
Market Energy Price, which is the clearing price for energy for Phase I.
Slater's forecast of the Market Energy Price is that provided to us by the
Partnership on March 19, 1998. The Market Energy Price as estimated by Slater is
summarized in Table 3.
<TABLE>
<CAPTION>
Table 3
Slater Forecast of Locational Based Market Price
<S> <C>
Year ($/MWh)
1998 $26.20
1999 25.80
2000 26.90
2001 28.60
2002 29.80
2003 31.10
2004 32.20
2005 33.50
2006 34.90
2007 35.90
</TABLE>
Power Sales to NiMo and the Marketplace. From the effective date of the Amended
PPA until an ISO/PE is established and fully functioning, the Partnership will
have the option to sell and deliver energy and capacity to NiMo up to a
specified Monthly Contract Quantity, plus up to 5% of the Monthly Contract
Quantity. NiMo will be required to take and pay for such energy and capacity as
the Partnership delivers to it under the Sale Option at the Market Energy Price,
and, if applicable, the Market Capacity Price.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 7
For any time-period during which the Partnership does not sell to NiMo, it may
sell such energy and associated capacity to third parties, provided that it
first offers NiMo the opportunity to purchase that energy and capacity at the
Market Energy Price, and, if applicable, the Market Capacity Price. The
Partnership is free to sell energy and capacity in excess of the Monthly
Contract Quantity to third parties without giving NiMo a right of first refusal.
In the Amended PPA Case, Selkirk receives revenues from the exercise of the Sale
Option. Additionally, there is a market for the energy generated from Phase I
which is in excess of the Monthly Contract Quantity. Under Slater's revised
dispatch for the Amended PPA Case, in 1998 Phase I will generate approximately
624,892 MWh assuming capacity of 79.9 MW, availability of 93 percent and a
dispatch of 96 percent. For purposes of this analysis, we have assumed that all
of Phase I's energy not sold to NiMo is sold to the marketplace at the Slater
forecasted Phase I Market Price.
Total revenues from projected Phase I energy sales over the term of the Bonds
are shown in Table 4.
<TABLE>
<CAPTION>
Table 4
Delivered Energy Revenues
<S> <C> <C> <C>
Total Slater Total
Delivered Market Price Revenue
Year Energy Sales ($/MWh) ($000)
---- ------------ -------------- ---------
1999 624,892 25.80 16,122
2000 633,262 26.90 17,035
2001 631,401 28.60 18,058
2002 637,911 29.80 19,010
2003 637,911 31.10 19,839
2004 646,318 32.20 20,811
2005 644,420 33.50 21,588
2006 644,420 34.90 22,490
2007 644,420 35.90 23,135
2008 646,318 36.70 23,720
2009 644,420 37.70 24,295
2010 644,420 38.70 24,939
2011 644,420 40.10 25,841
2012 190,860 41.40 7,902
</TABLE>
(1) - Year 2012 is a partial year due representing operations through April 16,
2012.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 8
The Partnership may also choose to sell capacity to NiMo or to the marketplace.
Assuming that the New York Power Pool does not have adequate capacity for either
existing load or to meet reserve requirements, Phase I capacity not sold to NiMo
may be sold to the marketplace. For purposes of the analysis, we have assumed
that the notional capacity corresponding to the Monthly Contract Quantity is
fully committed to NiMo. Any excess capacity is calculated as the nominal rating
of the unit of 79.9 MW less the capacity sold to NiMo. In 1998, the Amended PPA
calls for Phase I to have a maximum of 45 MW for sale to NiMo. The remaining
capacity of (79.9-45.0) 34.9 MW is assumed to be available for sale in 1998.
The market capacity price was estimated by Slater to be $3.2877 per MWh in the
fall of 1997. This price is used as the revenue basis for the sale of excess
capacity of Phase I. In 1998, the capacity of 34.9 MW is valued at $3.3896 per
MWh. The resulting revenue to Selkirk is approximately $1,036,279 in 1998. The
future capacity price is assumed to increase at the rate of general inflation of
3.1 percent per year.
1998 NIMO SETTLEMENT ADJUSTMENTS. In 1998 there are additional one-time
adjustments to the revenues under the NiMo Settlement Agreement which the
Partnership has provided and we have not independently verified. The net effect
of these adjustment has been estimated by the Partnership to be an increase in
1998 NiMo revenue of $8,054,041.
DISPATCH ASSUMPTIONS
The operation of Phases I and II under the MRA required that the dispatch
factors be adjusted to account for the changing treatment of utility generation
in New York State as a result of the MRA. The principal impact on the dispatch
due to the MRA is that many of the units competing with Phases I and II for
dispatch would be shutdown or restructured as merchant plants. A revised
dispatch forecast was provided to us by the Partnership as prepared by Slater
Consulting and dated March 19, 1998. The revised dispatch is a change to that
used in the Existing PPA Case and represents a dramatic increase in the dispatch
factors used for Phase I and somewhat less dramatic change for those used in
Phase II from those used in the Existing PPA Case. The dispatch factors for each
of Phase I and II under both the existing PPA Case and the Amended PPA Case are
shown in Table 5.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 9
<TABLE>
<CAPTION>
Table 5
Dispatch Factors
At 100% Availability
Existing PPA Case (%) Amended PPA Case (%)
<S> <C> <C> <C> <C>
Year Phase I Phase II Phase I Phase II
1998 31 92 96 99
1999 45 94 96 98
2000 45 95 97 99
2001 60 95 97 99
2002 69 95 98 99
2003 67 96 98 99
2004 73 96 99 100
2005 73 97 99 100
2006 70 97 99 100
2007 71 96 99 100
2008 67 96 99 100
2009 74 97 99 100
2010 68 98 99 100
2012 60 98 100 100
</TABLE>
MAJOR MAINTENANCE
We have accounted for the changes to the Major Maintenance expenditures by
estimating the Equivalent Operating Hours under the Amended PPA Case dispatch
assumptions and have calculated a schedule of deposits at a level which would
keep the major maintenance reserve fund from dropping to a level below $0 and,
after inclusion of interest income, will be adequate to continue to perform the
necessary maintenance under the proposed conditions. The required deposit and
scheduled expenditures are shown in Table 6.
<PAGE>
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 10
<TABLE>
<CAPTION>
Table 6
Major Maintenance
Schedule of Deposits and Withdrawals
($000)
<S> <C> <C> <C>
Deposits Withdrawals Balance
1998 8,104 2,605 7,185
1999 3,677 1,320 9,542
2000 1,959 8,264 3,237
2001 4,778 1,066 6,950
2002 4,238 1,701 9,487
2003 3,312 3,111 9,688
2004 1,509 9,524 1,673
2005 1,570 80 3,163
2006 4,630 332 7,462
2007 9,927 4,114 13,275
2008 710 265 13,720
2009 3,046 9,514 7,252
2010 1,379 5,004 3,627
2011 508 2,611 1,524
2012 0 1,524 0
- --------------------
Notes:
(1) - Beginning balance assumed to be $1,684,810 on January 1, 1998.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXISTING PPA BASE CASE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 1999 2000 2001 2002 2003 2004 2005
----- ----- ----- ----- ----- ----- ----- ----
PERFORMANCE
Unit 1
DMNC (kW) (1) 79,900 79,900 79,900 79,900 79,900 79,900 79,900 79,900
Availability Factor (2) 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%
Capacity Factor (3) 28.8% 41.8% 42.0% 55.8% 64.1% 62.3% 68.1% 67.9%
Energy Sales to
Niagara Mohawk (MWh)
Existing PPA Energy
Sales (MWh) (4) 201,747 292,803 293,666 390,619 448,987 436,132 476,445 475,070
Amended PPA Energy
Sales (MWh) (5) -- -- -- -- -- -- -- --
Fixed Energy
Sales (MWh) (6) -- -- -- -- -- -- -- --
Delivered Capacity
Sales (kW) (7) -- -- -- -- -- -- -- --
Unit 2
DMNC (kW) (1) 265,000 265,000 265,000 265,000 265,000 265,000 265,000 265,000
Availability Factor (2) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (3) 84.6% 86.5% 87.4% 87.4% 87.4% 88.3% 88.3% 89.2%
Energy Sales to
Con Ed (MWh) 1,964,833 2,007,547 2,034,946 2,028,904 2,028,904 2,050,260 2,056,366 2,071,617
Steam Sales (Mlbs) (8) 1,381,890 1,446,453 1,517,164 1,581,647 1,652,402 1,725,352 1,805,495 1,878,105
Contract Fuel Purchased
at Facility (BBtu)(9) 26,021,580 26,021,580 26,092,872 26,021,580 26,021,580 26,021,580 26,092,872 26,021,580
Contract Fuel
Purchased (BBtu) (10) 28,360,172 28,360,172 28,437,871 28,360,172 28,360,172 28,360,172 28,437,871 28,360,172
Fuel Required for
GE Plant (BBtu) (11) -- -- -- -- -- -- -- --
Fuel Consumption at
the Facility (BBtu)(12) 19,414,148 20,388,474 20,677,947 21,375,694 21,860,236 22,006,053 22,417,743 22,582,160
Fuel for Resale (BBtu) (13) 6,607,432 5,633,106 5,414,925 4,645,886 4,161,344 4,015,527 3,675,129 3,439,420
Spot Market Fuel
Purchased (BBtu) (14) -- -- -- -- -- -- -- --
COMMODITY PRICES
Electricity Price
Niagara Mohawk Contract
Existing PPA Fixed
Component ($ /kW-yr)(15) $279.04 $278.70 $281.83 $281.26 $282.33 $294.06 $296.09 $299.74
Existing PPA Variable
Component ($/MWh) (16) $30.75 $30.46 $31.47 $32.48 $33.24 $34.15 $35.00 $35.95
Amended PPA Delivered
Energy ($/MWh) (17) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Amended PPA Fixed
Component ($/MWh) (18) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Amended PPA Delivered
Capacity ($/kW-yr) (19) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Con Edison Contract
Fixed Component
($/kW-yr) (20) $305.38 $310.09 $323.07 $332.55 $344.03 $355.94 $368.41 $381.28
Variable Component
($/MWh) (21) $19.78 $20.18 $20.63 $21.61 $22.24 $22.86 $23.52 $24.18
Steam Price
($/Mlb) (22) $5.2408 $5.3148 $5.5249 $5.7977 $5.9689 $6.1454 $6.3274 $6.5150
Natural Gas Contract
Price ($/MMBtu) (23) $2.9994 $2.9365 $3.0282 $3.0981 $3.1548 $3.2013 $3.2603 $3.2872
Spot Price of Natural
Gas ($/MMBtu) (24) $2.3791 $2.3705 $2.4222 $2.5598 $2.6380 $2.7185 $2.8015 $2.8870
Natural Gas Resale
Price ($/MMBtu) (24) $2.5437 $2.5351 $2.5868 $2.7244 $2.8026 $2.8831 $2.9661 $3.0516
</TABLE>
1
<PAGE>
<TABLE>
<CAPTION>
EXISTING PPA BASE CASE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 1999 2000 2001 2002 2003 2004 2005
----- ----- ----- ----- ----- ----- ----- ----
OPERATING REVENUES ($000)
Phase I (NiMo) 28,800 31,495 32,079 35,488 37,819 38,741 40,695 41,400
Phase II (Con Ed) 127,970 131,134 136,298 140,937 145,529 150,733 155,829 161,274
Steam Revenue 0 238 617 1,044 1,497 1,990 2,531 3,104
Revenue from the Resale of Natural Gas 15,720 13,353 13,116 11,893 10,978 10,916 10,296 9,930
Other Income (25) 1,184 1,205 1,226 1,247 1,269 1,291 1,314 1,337
Interest Income (26) 2,078 2,152 2,219 2,288 2,359 2,432 2,507 2,585
Total Operating Revenues 175,751 179,578 185,555 192,897 199,451 206,103 213,173 219,630
OPERATING EXPENSES ($000)
Fuel Expense 37,296 37,902 39,162 41,267 42,487 43,865 45,325 46,630
Fuel Transportation Expense 47,768 45,377 46,954 46,596 46,984 46,925 47,393 46,594
Labor & Fringes 2,607 2,693 2,776 2,863 2,951 3,043 3,137 3,234
Operator Fees 2,801 2,903 2,993 2,819 2,357 2,369 2,381 2,395
Routine Maintenance 2,580 2,652 2,734 2,819 2,906 2,996 3,089 3,185
Deposits to Major Maintenance Fund (27) 4,385 5,007 4,632 2,297 2,161 2,757 6,212 5,688
GE Lease Payment 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Materials & Subcontracts 148 141 146 150 155 160 165 170
Utilities 3,801 3,752 3,776 3,783 3,814 3,656 4,056 3,920
Insurance & Property Taxes 3,348 3,547 3,779 4,012 4,247 4,482 4,719 4,957
Administrative & General 4,213 4,342 4,476 4,615 4,758 4,906 5,058 5,215
Wheeling Charges 5,597 5,597 5,597 5,597 5,770 5,949 6,134 6,324
Letter-of-Credit Fees 403 416 429 442 456 470 484 499
Gross Receipts Tax on Steam Revenue -- 8 22 37 52 70 89 109
Total Operating Expenses 115,946 115,337 118,477 118,297 120,098 122,648 129,241 129,919
NET OPERATING REVENUES ($000) 59,805 64,241 67,078 74,600 79,353 83,455 83,932 89,711
ANNUAL DEBT SERVICE
2007 Bonds (28)
Principal 3,298 4,822 7,307 11,062 13,529 17,365 19,587 25,230
Interest 13,954 13,662 13,202 12,441 11,457 10,206 8,657 6,843
2012 Bonds (29)
Principal -- -- -- -- -- -- -- --
Interest 20,385 20,385 20,385 20,385 20,385 20,385 20,385 20,385
Total Annual Debt Service 37,636 38,869 40,893 43,887 45,371 47,956 48,629 52,457
ANNUAL DEBT SERVICE COVERAGE (30) 1.59 1.65 1.64 1.70 1.75 1.74 1.73 1.71
AVERAGE DEBT COVERAGE (31) 1.7826
</TABLE>
2
<PAGE>
<TABLE>
<CAPTION>
EXISTING PPA BASE CASE
<S> <C> <C> <C> <C> <C> <C> <C>
2006 2007 2008 2009 2010 2011 2012 (32)
----- ----- ----- ----- ----- ----- ---------
PERFORMANCE
Unit 1
DMNC (kW) (1) 79,900 79,900 79,900 79,900 79,900 79,900 79,900
Availability Factor (2) 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%
Capacity Factor (3) 65.1% 66.0% 62.5% 68.8% 63.3% 63.3% 56.0%
Energy Sales to Niagara Mohawk (MWh)
Existing PPA Energy Sales (MWh) (4) 455,561 462,136 437,427 481,645 442,707 442,707 114,513
Amended PPA Energy Sales (MWh) (5) -- -- -- -- -- -- --
Fixed Energy Sales (MWh) (6) -- -- -- -- -- -- --
Delivered Capacity Sales (kW) (7) -- -- -- -- -- -- --
Unit 2
DMNC (kW) (1) 265,000 265,000 265,000 265,000 265,000 265,000 265,000
Availability Factor (2) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (3) 89.2% 88.3% 88.3% 89.2% 90.2% 90.2% 90.2%
Energy Sales to Con Ed (MWh) 2,071,617 2,050,260 2,056,366 2,071,617 2,092,974 2,092,974 1,049,604
Steam Sales (Mlbs) (8) 1,958,051 2,040,475 2,131,278 2,213,069 2,303,398 2,396,529 1,249,687
Contract Fuel Purchased at
Facility (BBtu)(9) 26,021,580 26,021,580 26,092,872 26,021,580 26,021,580 26,021,580 13,046,436
Contract Fuel Purchased (BBtu) (10) 28,360,172 28,360,172 28,437,871 28,360,172 28,360,172 28,360,172 14,218,935
Fuel Required for GE
Plant (BBtu) (11) -- -- -- -- -- -- --
Fuel Consumption at the
Facility (BBtu)(12) 22,503,055 22,446,625 22,387,839 22,882,949 22,829,634 22,895,367 11,325,160
Fuel for Resale (BBtu) (13) 3,518,525 3,574,955 3,705,033 3,138,631 3,191,946 3,126,213 1,721,276
Spot Market Fuel Purchased
(BBtu) (14) -- -- -- -- -- -- --
COMMODITY PRICES
Electricity Price
Niagara Mohawk Contract
Existing PPA Fixed Component $304.26 $307.89 $314.10 $316.46 $322.23 $326.61 $333.16
($/kW-yr) (15)
Existing PPA Variable Component $36.96 $37.96 $39.04 $40.03 $41.19 $42.33 $43.62
($/MWh) (16)
Amended PPA Delivered Energy $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
($/MWh) (17)
Amended PPA Fixed Component $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
($/MWh) (18)
Amended PPA Delivered Capacity $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
($/kW-yr) (19)
Con Edison Contract
Fixed Component ($/kW-yr) (20) $394.78 $408.93 $423.65 $439.57 $456.21 $473.59 $491.79
Variable Component ($/MWh) (21) $24.88 $25.61 $26.35 $27.10 $27.86 $28.67 $29.49
Steam Price ($/Mlb) (22) $6.7084 $6.9078 $7.1134 $7.3254 $7.5438 $7.7690 $8.0011
Natural Gas Contract Price
($/MMBtu) (23) $3.3481 $3.4117 $3.4716 $3.5543 $3.6335 $3.7152 $3.2337
Spot Price of Natural Gas
($/MMBtu) (24) $2.9751 $3.0658 $3.1593 $3.2557 $3.3550 $3.4573 $3.5626
Natural Gas Resale Price
($/MMBtu) (24) $3.1397 $3.2304 $3.3239 $3.4203 $3.5196 $3.6219 $3.7272
</TABLE>
3
<PAGE>
<TABLE>
<CAPTION>
EXISTING PPA BASE CASE
<S> <C> <C> <C> <C> <C> <C> <C>
2006 2007 2008 2009 2010 2011 2012
----- ----- ----- ----- ----- ----- ----
OPERATING REVENUES ($000)
Phase I(NiMo) 41,533 42,536 42,580 44,985 44,416 45,282 13,237
Phase II (Con Ed) 166,611 171,652 177,562 184,072 191,018 197,669 102,389
Steam Revenue 3,733 4,413 5,163 5,944 6,803 7,730 4,376
Revenue from the Resale of Natural Gas 10,468 10,960 11,705 10,218 10,709 10,808 5,117
Other Income (25) 1,361 1,385 1,409 1,434 1,460 1,486 712
Interest Income (26) 2,665 2,748 2,833 2,921 3,011 3,105 1,600
Total Operating Revenues 226,371 233,695 241,253 249,575 257,417 266,080 127,432
OPERATING EXPENSES ($000)
Fuel Expense 48,175 49,747 51,558 52,926 54,669 56,417 24,721
Fuel Transportation Expense 46,777 47,009 47,168 47,874 48,377 48,948 21,258
Labor & Fringes 3,335 3,438 3,545 3,654 3,768 3,885 2,002
Operator Fees 2,408 2,422 2,436 2,451 2,466 2,482 1,249
Routine Maintenance 3,284 3,385 3,490 3,598 3,710 3,825 1,972
Deposits to Major Maintenance Fund (27) 5,166 1,409 1,518 1,556 360 219 -
GE Lease Payment 1,000 1,000 1,000 1,000 1,000 1,000 500
Materials & Subcontracts 175 180 186 192 198 204 105
Utilities 4,025 4,125 4,242 4,350 4,478 4,598 2,270
Insurance & Property Taxes 5,096 5,236 5,378 5,520 5,664 5,810 2,978
Administrative & General 5,376 5,543 5,715 5,892 6,075 6,263 3,229
Wheeling Charges 6,520 6,722 6,930 7,145 7,367 7,595 7,830
Letter-of-Credit Fees 515 531 547 564 582 600 309
Gross Receipts Tax on Steam Revenue 131 154 181 208 238 271 153
Total Operating Expenses 131,982 130,902 133,893 136,931 138,951 142,115 68,578
NET OPERATING REVENUES ($000) 94,389 102,793 107,359 112,644 118,466 123,964 58,854
ANNUAL DEBT SERVICE
2007 Bonds (28)
Principal 31,657 28,396 -- -- -- -- --
Interest 4,524 1,621 -- -- -- -- --
2012 Bonds (29)
Principal -- 11,044 42,998 43,905 44,579 55,070 29,403
Interest 20,385 20,385 18,449 14,501 10,537 6,377 1,320
Total Annual Debt Service 56,566 61,447 61,447 58,406 55,117 61,447 30,723
ANNUAL DEBT SERVICE COVERAGE (30) 1.67 1.67 1.75 1.93 2.15 2.02 1.92
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
AMENDED PPA CASE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 1999 2000 2001 2002 2003 2004 2005
----- ----- ----- ----- ----- ----- ----- ----
PERFORMANCE
Unit 1
DMNC (kW) (1) 79,900 79,900 79,900 79,900 79,900 79,900 79,900 79,900
Availability Factor (2) 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%
Capacity Factor (3) 59.1% 89.3% 90.5% 90.2% 91.1% 91.1% 92.3% 92.1%
Energy Sales to
Niagara Mohawk (MWh)
Existing PPA Energy
Sales (MWh) (4) 100,874 -- -- -- -- -- -- --
Amended PPA Energy
Sales (MWh) (5) 206,670 624,892 633,262 631,401 637,911 637,911 646,318 644,420
Fixed Energy Sales
(MWh) (6) 162,700 328,200 353,450 396,700 418,500 430,750 446,850 456,500
Delivered Capacity
Sales (kW) (7) 34,900 34,900 32,900 27,900 27,900 24,900 27,900 26,900
Unit 2
DMNC (kW) (1) 265,000 265,000 265,000 265,000 265,000 265,000 265,000 265,000
Availability Factor (2) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (3) 91.1% 90.2% 91.1% 91.1% 91.1% 91.1% 92.0% 92.0%
Energy Sales to
Con Ed (MWh) 2,114,331 2,092,974 2,120,628 2,114,331 2,114,331 2,114,331 2,142,048 2,135,688
Steam Sales (Mlbs) (8) 1,381,890 1,446,453 1,517,164 1,581,647 1,652,402 1,725,352 1,805,495 1,878,105
Contract Fuel Purchased
at Facility (BBtu)(9) 26,021,580 26,021,580 26,092,872 26,021,580 26,021,580 26,021,580 26,092,872 26,021,580
Contract Fuel
Purchased (BBtu) (10) 28,360,172 28,360,172 28,437,871 28,360,172 28,360,172 28,360,172 28,437,871 28,360,172
Fuel Required for
GE Plant (BBtu) (11) -- -- -- -- -- -- -- --
Fuel Consumption at the
Facility (BBtu)(12) 21,972,775 23,368,158 23,693,422 23,671,849 23,771,769 23,821,825 24,161,440 24,153,590
Fuel for Resale
(BBtu) (13) 4,048,805 2,653,422 2,399,450 2,349,731 2,249,811 2,199,755 1,931,432 1,867,990
Spot Market Fuel
Purchased (BBtu) (14) -- -- -- -- -- -- -- --
COMMODITY PRICES
Electricity Price
Niagara Mohawk Contract
Existing PPA Fixed Component $272.52 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
($/kW-yr) (15)
Existing PPA Variable
Component ($/MWh) (16) $30.26 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Amended PPA Delivered Energy $26.20 $25.80 $26.90 $28.60 $29.80 $31.10 $32.20 $33.50
($/MWh) (17)
Amended PPA Fixed Component $77.28 $77.84 $79.50 $81.12 $82.80 $84.31 $84.89 $85.36
($/MWh) (18)
Amended PPA
Delivered Capacity
($/kW-yr) (19) $29.69 $30.61 $31.56 $32.54 $33.55 $34.59 $35.66 $36.77
Con Edison Contract
Fixed Component
($/kW-yr) (20) $305.38 $310.09 $323.07 $332.55 $344.03 $355.94 $368.41 $381.28
Variable Component
($/MWh) (21) $19.69 $20.17 $20.62 $21.60 $22.23 $22.87 $23.51 $24.19
Steam Price ($/Mlb) (22) $5.2408 $5.3148 $5.5249 $5.7977 $5.9689 $6.1454 $6.3274 $6.5150
Natural Gas Contract
Price ($/MMBtu) (23) $2.9290 $2.8931 $2.9784 $3.0485 $3.1484 $3.1971 $3.2577 $3.2864
Spot Price of Natural
Gas ($/MMBtu) (24) $2.3791 $2.3705 $2.4222 $2.5598 $2.6380 $2.7185 $2.8015 $2.8870
Natural Gas Resale
Price ($/MMBtu) (24) $2.5437 $2.5351 $2.5868 $2.7244 $2.8026 $2.8831 $2.9661 $3.0516
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
AMENDED PPA CASE
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 1999 2000 2001 2002 2003 2004 2005
----- ----- ----- ----- ----- ----- ----- ----
OPERATING REVENUES ($000)
Phase I(NiMo) 43,498 42,737 46,173 51,145 54,596 57,016 59,741 61,543
Phase II (Con Ed) 130,742 132,836 138,039 142,757 147,413 152,213 157,826 162,837
Steam Revenue 0 238 617 1,044 1,497 1,990 2,531 3,104
Revenue from the
Resale of Natural Gas 9,633 6,290 5,812 6,015 5,935 5,980 5,411 5,393
Other Income (25) 1,184 1,205 1,226 1,247 1,269 1,291 1,314 1,337
Interest Income (26) 2,078 2,152 2,219 2,288 2,359 2,432 2,507 2,585
Total Operating Revenues 187,133 185,458 194,086 204,495 213,068 220,922 229,330 236,799
OPERATING EXPENSES ($000)
Fuel Expense 34,400 35,752 36,873 39,298 41,802 43,230 44,778 46,169
Fuel Transportation Expense 48,668 46,296 47,826 47,157 47,488 47,441 47,864 47,033
Labor & Fringes 2,607 2,693 2,776 2,863 2,951 3,043 3,137 3,234
Operator Fees 2,801 2,903 2,993 2,819 2,357 2,369 2,381 2,395
Routine Maintenance 2,580 2,652 2,734 2,819 2,906 2,996 3,089 3,185
Deposits to Major
Maintenance Fund (27) 8,104 3,677 1,959 4,778 4,238 3,312 1,509 1,570
GE Lease Payment 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Materials & Subcontracts 148 141 146 150 155 160 165 170
Utilities 3,801 3,752 3,776 3,783 3,814 3,656 4,056 3,920
Insurance & Property Taxes 3,348 3,547 3,779 4,012 4,247 4,482 4,719 4,957
Administrative & General 4,213 4,342 4,476 4,615 4,758 4,906 5,058 5,215
Wheeling Charges 5,597 5,597 5,597 5,597 5,770 5,949 6,134 6,324
Letter-of-Credit Fees 403 416 429 442 456 470 484 499
Gross Receipts Tax
on Steam Revenue -- 8 22 37 52 70 89 109
Total Operating Expenses 117,670 112,776 114,387 119,370 121,994 123,083 124,463 125,779
NET OPERATING REVENUES ($000) 69,464 72,682 79,699 85,125 91,074 97,839 104,867 111,020
ANNUAL DEBT SERVICE
2007 Bonds (28)
Principal 3,298 4,822 7,307 11,062 13,529 17,365 19,587 25,230
Interest 13,954 13,662 13,202 12,441 11,457 10,206 8,657 6,843
2012 Bonds (29)
Principal - - - - - - - -
Interest 20,385 20,385 20,385 20,385 20,385 20,385 20,385 20,385
Total Annual Debt Service 37,636 38,869 40,893 43,887 45,371 47,956 48,629 52,457
ANNUAL DEBT SERVICE COVERAGE (30) 1.85 1.87 1.95 1.94 2.01 2.04 2.16 2.12
AVERAGE DEBT COVERAGE (31) 1.8793
</TABLE>
6
<PAGE>
<TABLE>
<CAPTION>
AMENDED PPA CASE
z<S> <C> <C> <C> <C> <C> <C> <C>
2006 2007 2008 2009 2010 2011 2012 (32)
----- ----- ----- ----- ----- ----- -----
PERFORMANCE
Unit 1
DMNC (kW) (1) 79,900 79,900 79,900 79,900 79,900 79,900 79,900
Availability Factor (2) 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%
Capacity Factor (3) 92.1% 92.1% 92.3% 92.1% 92.1% 92.1% 93.3%
Energy Sales to Niagara
Mohawk (MWh)
Existing PPA Energy
Sales (MWh) (4) -- -- -- -- -- -- --
Amended PPA Energy
Sales (MWh) (5) 644,420 644,420 646,318 644,420 644,420 644,420 190,860
Fixed Energy Sales (MWh) (6) 467,350 479,300 242,600 -- -- -- --
Delivered Capacity Sales (kW) (7) 25,900 24,500 79,900 79,900 79,900 79,900 79,900
Unit 2
DMNC (kW) (1) 265,000 265,000 265,000 265,000 265,000 265,000 265,000
Availability Factor (2) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (3) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Energy Sales to Con Ed (MWh) 2,135,688 2,135,688 2,142,048 2,135,688 2,135,688 2,135,688 1,071,024
Steam Sales (Mlbs) (8) 1,958,051 2,040,475 2,131,278 2,213,069 2,303,398 2,396,529 1,249,687
Contract Fuel Purchased
at Facility (BBtu)(9) 26,021,580 26,021,580 26,092,872 26,021,580 26,021,580 26,021,580 13,046,436
Contract Fuel
Purchased (BBtu) (10) 28,360,172 28,360,172 28,437,871 28,360,172 28,360,172 28,360,172 14,218,935
Fuel Required for GE
Plant (BBtu) (11) -- -- -- -- -- -- --
Fuel Consumption at
the Facility (BBtu)(12) 24,218,177 24,284,378 24,423,806 24,421,789 24,493,083 24,566,161 12,378,988
Fuel for Resale (BBtu) (13) 1,803,403 1,737,202 1,669,066 1,599,791 1,528,497 1,455,419 667,448
Spot Market Fuel
Purchased (BBtu) (14) -- -- -- -- -- -- --
COMMODITY PRICES
Electricity Price
Niagara Mohawk Contract
Existing PPA Fixed Component $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
($/kW-yr) (15)
Existing PPA Variable
Component ($/MWh)(16) $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Amended PPA Delivered Energy $34.90 $35.90 $36.70 $37.70 $38.70 $40.10 $41.40
($/MWh) (17)
Amended PPA Fixed Component $85.87 $86.93 $87.18 $0.00 $0.00 $0.00 $0.00
($/MWh) (18)
Amended PPA Delivered Capacity $37.91 $39.08 $40.29 $41.54 $42.83 $44.16 $45.53
($/kW-yr) (19)
Con Edison Contract
Fixed Component ($/kW-yr) (20) $394.78 $408.93 $423.65 $439.57 $456.21 $473.59 $491.79
Variable Component ($/MWh) (21) $24.89 $25.61 $26.35 $27.11 $27.89 $28.70 $29.53
Steam Price ($/Mlb) (22) $6.7084 $6.9078 $7.1134 $7.3254 $7.5438 $7.7690 $8.0011
Natural Gas Contract
Price ($/MMBtu) (23) $3.3502 $3.4166 $3.4801 $3.5635 $3.6461 $3.7306 $3.1226
Spot Price of Natural
Gas ($/MMBtu) (24) $2.9751 $3.0658 $3.1593 $3.2557 $3.3550 $3.4573 $3.5626
Natural Gas Resale
Price ($/MMBtu) (24) $3.1397 $3.2304 $3.3239 $3.4203 $3.5196 $3.6219 $3.7272
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
AMENDED PPA CASE
<S> <C> <C> <C> <C> <C> <C> <C>
2006 2007 2008 2009 2010 2011 2012(32)
----- ----- ----- ----- ----- ----- -----
OPERATING REVENUES ($000)
Phase I(NiMo) 63,602 65,759 48,090 27,614 28,361 29,370 8,965
Phase II (Con Ed) 168,223 173,834 179,818 185,838 192,273 198,964 103,067
Steam Revenue 3,733 4,413 5,163 5,944 6,803 7,730 4,376
Revenue from the Resale of
Natural Gas 5,365 5,326 5,273 5,208 5,128 5,032 2,378
Other Income (25) 1,361 1,385 1,409 1,434 1,460 1,486 712
Interest Income (26) 2,665 2,748 2,833 2,921 3,011 3,105 1,600
Total Operating Revenues 244,949 253,464 242,586 228,960 237,036 245,685 121,099
OPERATING EXPENSES ($000)
Fuel Expense 47,726 49,329 51,121 52,684 54,438 56,244 23,106
Fuel Transportation Expense 47,288 47,567 47,845 48,378 48,965 49,558 21,294
Labor & Fringes 3,335 3,438 3,545 3,654 3,768 3,885 2,002
Operator Fees 2,408 2,422 2,436 2,451 2,466 2,482 1,249
Routine Maintenance 3,284 3,385 3,490 3,598 3,710 3,825 1,972
Deposits to Major
Maintenance Fund (27) 4,630 9,927 710 3,046 1,379 508 0
GE Lease Payment 1,000 1,000 1,000 1,000 1,000 1,000 500
Materials & Subcontracts 175 180 186 192 198 204 105
Utilities 4,025 4,125 4,242 4,350 4,478 4,598 2,270
Insurance & Property Taxes 5,096 5,236 5,378 5,520 5,664 5,810 2,978
Administrative & General 5,376 5,543 5,715 5,892 6,075 6,263 3,229
Wheeling Charges 6,520 6,722 6,930 7,145 7,367 7,595 7,830
Letter-of-Credit Fees 515 531 547 564 582 600 309
Gross Receipts Tax on
Steam Revenue 131 154 181 208 238 271 153
Total Operating Expenses 131,508 139,560 133,325 138,684 140,327 142,841 66,999
NET OPERATING REVENUES ($000) 113,442 113,904 109,262 90,276 96,710 102,844 54,100
ANNUAL DEBT SERVICE
2007 Bonds (28)
Principal 31,657 28,396 -- -- -- -- --
Interest 4,524 1,621 -- -- -- -- --
2012 Bonds (29)
Principal -- 11,044 42,998 43,905 44,579 55,070 29,403
Interest 20,385 20,385 18,449 14,501 10,537 6,377 1,320
Total Annual
Debt Service 56,566 61,447 61,447 58,406 55,117 61,447 30,723
ANNUAL DEBT SERVICE
COVERAGE (30) 2.01 1.85 1.78 1.55 1.75 1.67 1.76
</TABLE>
<PAGE>
Footnotes to Existing PPA Base Case
and the Amended PPA Case
1. Represents the Phase I and Phase II contract capacity tested output under
the Niagara Mohawk PPA and the Con Edison PPA.
2. Availability as estimated by Beck.
3. Capacity factors based on annual dispatch factor as estimated by Slater
Consulting adjusted for the assumed availability. For the Amended PPA Case
the capacity factor for 1998 is a weighted average based on the dispatch
factors for the Existing and Amended PPA Cases.
4. Existing PPA Energy Sales is equal to the energy sales to NiMo under the
existing PPA in MWh calculated as the capacity of 79,900 kW times the
capacity factor. For the Amended PPA Case, in 1998 this is based on sales
between January 1 and June 30, 1998.
5. Delivered Energy Sales is equal to the energy sales to NiMo and potentially
third parties under the Amended PPA in MWh calculated as the capacity of
79,900 kW times the capacity factor. For the Amended PPA Case, in 1998 this
is based on sales between July 1 and December 31, 1998.
6. Fixed Energy Sales is equal to the contract year (July 1 - June 30) Annual
Contract Volume in MWh per Attachment I-A in the Amended PPA, which
quantity has been prorated on a calendar year basis.
7. Delivered Capacity Sales is equal to the DMNC less the maximum Monthly
Contract Quantity of Capacity.
8. Steam sales as estimated by the Partnership based on 237,750 pph in 1998
and assumed to increase at the rate of 3.1 percent per year, minus 80,000
pph supplied by GEP.
9. Contract fuel purchased at the Facility for Phase I and Phase II based on
net purchases of 21,357 MMBtu per day and 55,935 MMBtu per day,
respectively, less a reduction in the Phase I Paramount contract quantity
of 6,000 MMBtu per day.
10. Contract fuel purchased for Phase I and Phase II based on purchases of
23,391 MMBtu per day and 60,308 MMBtu per day, respectively, less a
reduction in the Phase I Paramount contract quantity for the capacity
release of 6,000 MMBtu per day.
11. No auxiliary fuel consumption has been projected by the Partnership since
the dispatch factors projected by Slater are sufficiently high to forecast
that at least one unit will be on line at all times.
12. Fuel consumption at the Facility is based on varying levels of dispatch of
Phase I and Phase II and upon the level of steam sales and Phase I start-up
fuel as estimated by the Partnership.
13. Fuel for Resale is equal to (1) Phase I net fuel purchases at the Facility
of 21,357 MMBtu per day less the reduction in the Phase I Paramount
contract quantity of 6,000 MMBtu per day, less the fuel consumed by Phase
I, plus; (2) Phase II net fuel purchases at the Facility of 55,935 MMBtu
per day less the fuel consumed by Phase II.
14. Fuel for supplemental firing is included in Fuel Consumption. The
Partnership estimates that enough contract fuel will be available to meet
supplemental firing fuel requirements and that no spot market purchases
will be necessary.
15. The fixed component from the Existing Niagara Mohawk PPA includes a
contractual capacity payment of $12.54 per kW-month through 2002, $13.19
per kW-month through 2007, and $13.29 per kW-month through the remainder of
the term of the Existing Niagara Mohawk PPA, all less a discount of $2.05
per kW-month for those hours Phase I is dispatched on line; plus a fixed
transportation charge of $6.4157 per kW-month in January 1990 escalating at
one-half the rate of change in the CPI-NJ, assumed to be 3.1 percent per
year for the period beyond which actual indices were available, plus a
fixed O&M payment of $3.1158 per kW-month in January 1990 escalating at the
rate of change in the CPI-NJ. For the Amended PPA Case the Existing PPA
Fixed Component is based on an annual weighted average dispatch factor for
the Existing and Amended PPA Case.
<PAGE>
Footnotes to Existing PPA Base Case
and the Amended PPA Case (continued)
16. The variable component Existing Niagara Mohawk PPA includes an energy
payment of $1.4286 per MMBtu on April 1, 1988 escalated each April 1 by the
rate of change in Niagara Mohawk's weighted average cost of No. 6 fuel oil
and natural gas, which is assumed to escalate at the rate of 3.1 percent
per year for the period beyond which actual indices were available; plus a
variable transportation charge equal to $6.6732 per MWh in December 1993
escalated monthly at one-half the rate of change in the CPI-NJ, plus a
variable O&M payment of $4.013 per MWh on March 1, 1989 escalating at the
rate of change in the CPI-NJ. For the Amended PPA Case the Existing PPA
Variable Component is based on an annual weighted average dispatch factor
for the Existing and Amended PPA Cases.
17. The Amended PPA Delivered Energy payment is equal to the Market Energy
Price which is based upon an economic dispatch analysis prepared by Slater
Consulting.
18. The Amended PPA Fixed Component payment is equal to the sum of (1) the
Contract Capacity Payment, plus; (2) the Energy Payment, plus; (3) the
Transportation Payment, plus; (4) the Operation and Maintenance Payment;
(5) less the Market Energy Price which has been deducted. Each component is
adjusted by the DMNC Adjustment. The Contract Capacity Payment is
stipulated for the term of the Agreement and is equal to $73.83 per MWh and
$73.60 per MWh for the first 2 contract years. The Energy Payment is
stipulated by the Agreement to be $15.80 per MWh and $15.95 per MWh for the
first 2 contract years, or until the Independent System Operator is
established. The Transportation Payment is stipulated by the Agreement to
be $7.15 per MWh and $7.35 per MWh for the first 2 contract years, or until
the Independent System Operator is established. The Operation and
Maintenance Payment is stipulated by the Agreement to be $6.70 per MWh and
$6.89 per MWh for the first 2 contract years, or until the Independent
System Operator is established. The DMNC adjustment is a factor which is
equal to the current DMNC divided by 79.9 MW. The Transportation Price and
the O&M Price are adjusted by the Inflation Escalation Factor which is
equal to the latest CPI - All Urban Consumers for New York - Northern New
Jersey-Long Island, all Items divided by the CPI for July 1998 which is
173.0. The Market Energy Price is equal to $26.30 per MWh in the first
contract year as estimated by Slater.
19. The Amended PPA Delivered Capacity payment is equal to the Slater market
price for capacity which is estimated to be $2.40 per kW-month in 1997 and
is escalated at the assumed rate of change in the CPI of 3.1 percent per
year.
20. The fixed component from the Con Edison PPA is equal to $10.0476 per
kW-month in June 1992 escalated monthly be a factor of 1.00407, plus a
fixed O&M component of $1.90 per kW-month escalated from March 1, 1989 at
the rate of change in the CPI-NJ, plus a fixed transportation charge of
$37.1083 per MMBtu on March 1, 1989 escalated at one-half the rate of
change in the CPI-NJ based on: (1) the contractual base daily quantity of
gas of 48,250 MMBtu, (corresponding to a DMNC of 252.3 MW) adjusted for the
actual DMNC of 265 MW, up to a maximum DMNC of 265 MW; and (2) the annual
availability.
21. The variable component Con Edison PPA includes a fuel payment of $1.49 per
MMBtu on April 1, 1988 escalated at the rate of change of the NY-RWAP,
which is assumed to escalate at the rate of 3.1 percent per year for the
period beyond which the actual indices were available; plus a variable O&M
payment of $2.00 per MWh on March 1, 1989 escalated monthly at the rate of
change in the CPI-NJ; plus a savings component equal to 50 percent of the
difference between the aggregate fuel supply and transportation costs of
Selkirk Phase II and the aggregate ceiling price under the Con Edison PPA.
22. Steam price is equal to GEP's avoided cost of producing steam which is
calculated as the sum of an overhead component of $0.179 per Mlb and a
variable component of $0.89 per Mlb, both in March 1989, and escalated at
the rate of change in the CPI-NJ; plus a fuel component of $3.218 per Mlb
in March 1989 escalated at the rate of change in Niagara Mohawk's weighted
average cost of fossil fuel assumed to be 3.1 percent per year, as
estimated by the Partnership and reviewed by the Gas Consultant.
23. Natural gas contract price represents the weighted average of Phase I and
Phase II contract prices calculated by Beck based on contract pricing
estimated by the Partnership and reviewed by the Gas Consultant.
<PAGE>
Footnotes to Existing PPA Base Case
and the Amended PPA Case (continued)
24. Spot gas price and resale gas price as estimated by the Partnership, and
reviewed by the Gas Consultant.
25. Includes peak shaving and additional gas transportation revenue. Peak
shaving revenue as estimated by the Partnership and reviewed by the Gas
Consultant equal to $717,000 per year in 1998 dollars escalated at one-half
the assumed rate of change in the CPI-NJ. Additional gas transportation
revenue as estimated by the Partnership and reviewed by the Gas Consultant
equal to $317,000 per year in 1998 dollars escalated at one-half the
assumed rate of change in the CPI-NJ.
26. Interest income as estimated by the Partnership for the November 1997
Independent Engineer's Report based upon historical balances in all
Partnership funds and a rate of return of 5.19 percent per year for 1998
and assumed to escalate at 3.1 percent per year based upon increases in the
net operating revenue.
27. Major Maintenance fund deposits based on equivalent operating hours under
each of Existing PPA Base Case and Amended PPA Case operating conditions
which reflect the different dispatch assumptions. The Existing PPA Base
Case deposits are in accordance with the revised Schedule 6.11 of the Trust
Indenture. The Amended PPA Case deposits are estimated using the projected
dispatch assumptions provided by Slater Consulting.
28. Debt service on the 2007 bonds based on a principal amount of the 2007
Bonds of $165,000,000 and an interest rate of 8.65 percent per year,
semi-annual principal payments beginning June 26, 1996.
29. Debt service on the 2012 bonds based on a principal amount of the 2012
Bonds of $227,000,000 and an interest rate of 8.98 percent per year,
semi-annual principal payments beginning December 26, 2007.
30. Annual debt service coverage calculated as net revenues divided by total
debt service.
31. Average debt service coverage calculated as total net revenues divided by
total debt service for the period beginning January 1, 1998 and ending June
26, 2012.
32. Represents partial year based on final amortization of the Bonds on June
26, 2012.
<PAGE>
ATTACHMENT C
SELKIRK COGEN PARTNERS, L.P.
SELKIRK COGEN PARTNERS, L.P.
OFFICER'S CERTIFICATE
August 31, 1998
Bankers Trust Company,
as Trustee
Corporate Trust Department
4 Albany Street
New York, New York 10006
Ladies and Gentlemen:
This Officer's Certificate is being delivered by the undersigned, Selkirk
Cogen Partners, L.P., a Delaware limited partnership (the "Partnership"),
pursuant to Section 6.20 of the Trust Indenture dated as of May 1, 1994 among
the Partnership, Selkirk Cogen Funding Corporation and Bankers Trust Company, as
Trustee (the "Indenture").
The Partnership has entered into the following transactions, which
collectively are referred to in this Officer's Certificate as the "Unit l
Restructuring": (1) the restructuring of the NIMO Power Purchase Agreement
between the Partnership and NIMO pursuant to the Master Restructuring Agreement
dated as of July 9, 1997 among NIMO, the Partnership and other IPP's, as
amended, (2) the execution, delivery and performance of the agreements listed on
Exhibit A to this Officer's Certificate, and (3) the completion of the other
transactions listed on Exhibit A. Capitalized terms used and not defined herein
shall have the meanings assigned to such terms in Exhibit A and in the
Indenture.
The Partnership hereby certifies to you as follows:
1. The undersigned officer of JMC Selkirk, Inc., the Managing General Partner,
is its Authorized Representative, has read the provisions of Section 6.20
and related definitions of the Indenture and has reviewed the documents
which comprise the Unit 1 Restructuring and made such other examination or
investigation as is necessary to enable the Partnership to express an
informed opinion as to the matters addressed by this Officer's Certificate.
2. The implementation of the Unit 1 Restructuring, including (a) the
execution, delivery and performance of the Amended and Restated NIMO Power
Purchase Agreement, the Amended Paramount Contract and the Amended
TransCanada Agreement, and the termination of the NIMO License Agreement,
could not reasonably be expected to result in a Material Adverse Change. As
required by Section 6.20(a)(i) of the Indenture, the foregoing
determination is concurred with by the Independent Engineer in the
Independent Engineer's Certificate addressed to you and dated August 31,
1998, executed by R.W. Beck, Inc. (the "Independent Engineer's
Certificate") and, with respect to the Amended
24 Power Park Drive, Selkirk, New York 12158-2299
Telephone (518) 475-5773 Telefax (518) 475-5199
<PAGE>
SC
Paramount Contract and the Amended TransCanada Agreement, by the Gas
Consultant in the Gas Consultant's Certificate addressed to you and dated
August 28, 1998, executed by C.C. Pace Resources (the "Gas Consultant's
Certificate").
3. After giving effect to the implementation of the Unit 1 Restructuring,
including the execution, delivery and performance of the Amended and
Restated NIMO Power Purchase Agreement, the Amended Paramount Contract and
the Amended TransCanada Agreement, and the termination of the NIMO License
Agreement, the minimum annual Projected Debt Service Coverage Ratio will be
equal to or exceed 1.5:1 and the average annual Projected Debt Service
Coverage Ratio for the remaining term of the Bonds will be equal to or
exceed 1.75:1. As required by Section 6.20(a)(ii) of the Indenture, the
foregoing determination is concurred with in the Independent Engineer's
Certificate. The full calculation of the Projected Debt Service Coverage
Ratio (together with supporting documentation) is set forth in Attachment B
to the Independent Engineer's Certificate.
4. The Partnership's entering into the Additional Contracts listed on Exhibit
A could not reasonably be expected to result in a Material Adverse Change
and would not impair the ability of the Partnership to perform its
obligations under the other Project Agreements. As required by Section
6.20(c)(i) of the Indenture, the foregoing determination is concurred with
in the Independent Engineer's Certificate and, to the extent such matters
relate to the Partnership's fuel supply, in the Gas Consultant's
Certificate.
5. The Partnership will be furnishing to the Collateral Agent the Ancillary
Documents related to the Additional Contracts listed on Exhibit A within a
reasonable period, to the extent required under Section 6.20(c)(i)(B) of
the Indenture. The Partnership was unable to obtain a Consent or Opinion of
Counsel with respect to the other IPP parties to the MRA or to the
Allocation Agreement using commercially reasonable efforts, due to the
large number of Persons involved.
6. With respect to each of the transactions which comprise the Unit 1
Restructuring, the Partnership has complied with the covenants set forth in
Section 6.20 of the Indenture, and no Event of Default under this Indenture
has occurred and is continuing.
2
<PAGE>
SC
IN WITNESS WHEREOF, the undersigned has executed this Officer's Certificate
as of the date first written above.
SELKIRK COGEN PARTNERS, L.P.
By: JMC SELKIRK, INC.,
its Managing General Partner
By: /s/John R. Cooper
---------------------------
Name: John R. Cooper
Title: Vice-President
3
<PAGE>
SC
EXHIBIT A
RESTRUCTURING DOCUMENTS
1. Master Restructuring Agreement dated as of July 9, 1997 among Niagara
Mohawk Power Corporation ("NIMO"), Selkirk Cogen Partners, L.P. (the
"Partnership") and the other IPP's named therein (as amended, the "MRA")
a. First Amendment dated March 31, 1998
b. Second Amendment dated April 21, 1998
c. Third Amendment dated April 30, 1998
d. Fourth Amendment dated May 7, 1998
e. Fifth Amendment dated June 2, 1998
2. Allocation Agreement dated April 21, 1998 among the Partnership and certain
other IPP's (as amended, the "Allocation Agreement")
a. First Amendment dated May 7, 1998
3. Amended and Restated Power Purchase Agreement dated as of July 1, 1998
between the Partnership and NIMO (the "Amended and Restated NIMO Power
Purchase Agreement")
4. Mutual General Release and Agreement dated as of July 1, 1998 between the
Partnership and NIMO (the "Mutual Release")
5. Second Amended and Restated Gas Contract dated May 6, 1998 between the
Partnership and Paramount Resources Limited ("Paramount") (the "Amended
Paramount Contract")
6. Agreement with respect to Gas Transportation dated as of May 6, 1998
between the Partnership and Paramount (the "Paramount Transportation
Agreement")
7. Amendment to Gas Transportation Agreement dated as of July 20, 1998 between
the Partnership and TransCanada Pipelines Ltd. ("TransCanada") (the
"Amended TransCanada Agreement")
8. Three-party agreement with respect to Items 6 and 7 above dated as of July
20, 1998 among the Partnership, Paramount and TransCanada (the "TransCanada
Consent")
9. The Partnership's agreement with NIMO (contained in the Mutual Release) to
terminate the existing License Agreement dated as of October 23, 1992
between the Partnership and NIMO (the "License Agreement")
CC PACE
RESOURCES
GAS CONSULTANT'S CERTIFICATE
August 28, 1998
Bankers Trust Company, as Trustee
Corporate Trust Department
4 Albany Street
New York, New York 10006
Re: GAS CONSULTANT REVIEW OF GAS CONTRACT MODIFICAITONS
Ladies and Gentlemen:
C.C. Pace Resources ("Pace") has reviewed the Second Amended and Restated Gas
Purchase Contract between Paramount Resources Ltd. ("Paramount") and Selkirk
Cogen Partners, L.P. ("Selkirk"), dated as of May 6, 1998, ("Revised Paramount
Contract") and the other Gas Contract Modifications1 and the risk issues related
to the Gas Contract Modifications in our role as Fuel Consultant under the May
1, 1994 Trust Indenture (the "Indenture"). Pace hereby certifies to you as
follows:
1. The undersigned officer of Pace is its Authorized Representative (as
defined in the Indenture), has read the provisions of Sections 6.20(a)(i)
and 6.20(c)(i) and related definitions of the Indenture and has made such
examination or investigation as is necessary to enable the expression of an
informed opinion as to the matters addressed in this Gas Consultant's
Certificate.
2. Pace finds, and concurs with the Partnership's determination, pursuant to
Sections 6.20(a)(i) and 6.20(c)(i) of the Indenture as set forth in
Attachment B, that the implementation of the Gas Contract Modifications
could not reasonably be expected to result in a "Material Adverse Change"
within the meaning of the Indenture ("No MAC") and, to the extent
applicable, would not impair the ability of the Partnership to perform its
obligations under the other Project Agreements (as defined in the
Indenture).
- ---------------------------
1 For purposes of this Gas Consultant's Certificate, "Gas Contract
Modifications" means and includes the execution, delivery and performance by
Selkirk of the Revised Paramount Contract and the other agreements listed on
Attachment A to this Gas Consultant's Certificate. The Gas Contract
Modifications are being undertaken in connection with the restructuring of the
current Unit 1 power purchase agreement between Selkirk and Niagara Mohawk Power
Corporation ("NiMo") pursuant to the master Restructuring Agreement dated as of
July 9, 1997 among NiMo, Selkirk and other IPP's (the "NiMo restructuring").
4401 Fair Lakes Court Suite 400 Fairfax, Virginia 22033-3848 Tel: (703) 818-9100
Fax: (703) 818-9108
<PAGE>
Bankers Trust Company, as Trustee
August 28, 1998
Page 2
This finding is predicated on the NiMo restructuring and on specific provisions
contained in the Amended and Restated Power Purchase Agreement with NiMo
("Amended PPA"), which are under the Indenture purview of the Independent
Engineer. The scope of our analysis as Gas Consultant is to opine, given the
changes in the Amended PPA, on the proposed change in the fuel supply
arrangement.
In summary, Pace bases its No MAC determination on the following conclusions
regarding the Gas Contract Modifications:
. Contracted firm supply of 16,400 Mcf/day under the Revised Paramount Contract
is adequate to meet the maximum requirements of Unit 1.
. Strong linkage exists between natural gas costs and power revenues due to the
use of an identical natural gas spot price index in the Revised Paramount
Contract and the Amended PPA.
. Sufficiently secure firm gas supply is assured through spot market-based
pricing near the Western Canada gas production area and reserve dedication,
liquidated damages, and additional Paramount obligations.
. Paramount's obligations are well supported by Paramount's financial and
market position.
. Required regulatory approvals of the Revised Paramount Contract have been
obtained.
Attachment C summarizes Pace's analysis supporting these findings.
IN WITNESS WHEREOF, the undersigned has executed this Gas Consultant's
Certificate as of the date first written above.
C.C. PACE RESOURCES
By: /s/ Daniel E. White
--------------------------
Name: Daniel E. White
Title: Senior Vice President
<PAGE>
ATTACHMENT A
RESTRUCTURING DOCUMENTS
1. Second Amended and Restated Gas Contract dated May 6, 1998, between Selkirk
and Paramount (the "Revised Paramount Contract").
2. Agreement with respect to Gas Transportation dated May 6, 1998, between
Selkirk and Paramount (the "Revised Paramount Contract").
3. Amendment to Gas Transportation Agreement dated July 20, 1998, between
Selkirk and TransCanada PipeLines Ltd. ("TransCanada") (the "Amended
TransCanada Agreement").
4. Three-party agreement with respect to Items 2 and 3 above dated July 20,
1998, among Selkirk, Paramount and TransCanada (the "TransCanada Consent").
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A-1
<PAGE>
ATTACHMENT B
SELKIRK COGEN PARTNERS, L.P.
OFFICER'S CERTIFICATE
August 31, 1998
Bankers Trust Company,
as Trustee
Corporate Trust Department
4 Albany Street
New York, New York 10006
Ladies and Gentlemen:
This Officer's Certificate is being delivered by the undersigned,
Selkirk Cogen Partners, L.P., a Delaware limited partnership (the
"Partnership"), pursuant to Section 6.20 of the Trust Indenture dated as of May
1, 1994 among the Partnership, Selkirk Cogen Funding Corporation and Bankers
Trust Company, as Trustee (the "Indenture").
The Partnership has entered into the following transactions, which
collectively are referred to in this Officer's Certificate as the "Unit l
Restructuring": (1) the restructuring of the NIMO Power Purchase Agreement
between the Partnership and NIMO pursuant to the Master Restructuring Agreement
dated as of July 9, 1997 among NIMO, the Partnership and other IPP's, as
amended, (2) the execution, delivery and performance of the agreements listed on
Exhibit A to this Officer's Certificate, and (3) the completion of the other
transactions listed on Exhibit A. Capitalized terms used and not defined herein
shall have the meanings assigned to such terms in Exhibit A and in the
Indenture.
The Partnership hereby certifies to you as follows:
1. The undersigned officer of JMC Selkirk, Inc., the Managing
General Partner, is its Authorized Representative, has read the
provisions of Section 6.20 and related definitions of the
Indenture and has reviewed the documents which comprise the Unit
1 Restructuring and made such other examination or investigation
as is necessary to enable the Partnership to express an informed
opinion as to the matters addressed by this Officer's
Certificate.
2. The implementation of the Unit 1 Restructuring, including (a) the
execution, delivery and performance of the Amended and Restated
NIMO Power Purchase Agreement, the Amended Paramount Contract and
the Amended TransCanada Agreement, and the termination of the
NIMO License Agreement, could not reasonably be expected to
result in a Material Adverse Change. As required by Section
6.20(a)(i) of the
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B-1
<PAGE>
Indenture, the foregoing determination is concurred with by the
Independent Engineer in the Independent Engineer's Certificate
addressed to you and dated August 31, 1998, executed by R.W.
Beck, Inc. (the "Independent Engineer's Certificate") and, with
respect to the Amended Paramount Contract and the Amended
TransCanada Agreement, by the Gas Consultant in the Gas
Consultant's Certificate addressed to you and dated August 28,
1998, executed by C.C. Pace Resources (the "Gas Consultant's
Certificate").
3. After giving effect to the implementation of the Unit 1
Restructuring, including the execution, delivery and performance
of the Amended and Restated NIMO Power Purchase Agreement, the
Amended Paramount Contract and the Amended TransCanada Agreement,
and the termination of the NIMO License Agreement, the minimum
annual Projected Debt Service Coverage Ratio will be equal to or
exceed 1.5:1 and the average annual Projected Debt Service
Coverage Ratio for the remaining term of the Bonds will be equal
to or exceed 1.75:1. As required by Section 6.20(a)(ii) of the
Indenture, the foregoing determination is concurred with in the
Independent Engineer's Certificate. The full calculation of the
Projected Debt Service Coverage Ratio (together with supporting
documentation) is set forth in Attachment B to the Independent
Engineer's Certificate.
4. The Partnership's entering into the Additional Contracts listed
on Exhibit A could not reasonably be expected to result in a
Material Adverse Change and would not impair the ability of the
Partnership to perform its obligations under the other Project
Agreements. As required by Section 6.20(c)(i) of the Indenture,
the foregoing determination is concurred with in the Independent
Engineer's Certificate and, to the extent such matters relate to
the Partnership's fuel supply, in the Gas Consultant's
Certificate.
5. The Partnership will be furnishing to the Collateral Agent the
Ancillary Documents related to the Additional Contracts listed on
Exhibit A within a reasonable period, to the extent required
under Section 6.20(c)(i)(B) of the Indenture. The Partnership was
unable to obtain a Consent or Opinion of Counsel with respect to
the other IPP parties to the MRA or to the Allocation Agreement
using commercially reasonable efforts, due to the large number of
Persons involved.
6. With respect to each of the transactions which comprise the Unit
1 Restructuring, the Partnership has complied with the covenants
set forth in Section 6.20 of the Indenture, and no Event of
Default under this Indenture has occurred and is continuing.
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B-2
<PAGE>
IN WITNESS WHEREOF, the undersigned has executed this Officer's
Certificate as of the date first written above.
SELKIRK COGEN PARTNERS, L.P.
By: JMC SELKIRK, INC.,
its Managing General Partner
By: /s/John R. Cooper
-------------------------------
Name: John R. Cooper
Title: Vice-President
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B-3
<PAGE>
RESTRUCTURING DOCUMENTS
1. Master Restructuring Agreement dated as of July 9, 1997 among Niagara
Mohawk Power Corporation ("NIMO"), Selkirk Cogen Partners, L.P. (the
"Partnership") and the other IPP's named therein (as amended, the "MRA")
a. First Amendment dated March 31, 1998
b. Second Amendment dated April 21, 1998
c. Third Amendment dated April 30, 1998
d. Fourth Amendment dated May 7, 1998
e. Fifth Amendment dated June 2, 1998
2. Allocation Agreement dated April 21, 1998 among the Partnership and certain
other IPP's (as amended, the "Allocation Agreement")
a. First Amendment dated May 7, 1998
3. Amended and Restated Power Purchase Agreement dated as of July 1, 1998
between the Partnership and NIMO (the "Amended and Restated NIMO Power
Purchase Agreement")
4. Mutual General Release and Agreement dated as of July 1, 1998 between the
Partnership and NIMO (the "Mutual Release")
5. Second Amended and Restated Gas Contract dated May 6, 1998 between the
Partnership and Paramount Resources Limited ("Paramount") (the "Amended
Paramount Contract")
6. Agreement with respect to Gas Transportation dated as of May 6, 1998
between the Partnership and Paramount (the "Paramount Transportation
Agreement")
7. Amendment to Gas Transportation Agreement dated as of July 20, 1998 between
the Partnership and TransCanada Pipelines Ltd. ("TransCanada") (the
"Amended TransCanada Agreement")
8. Three-party agreement with respect to Items 6 and 7 above dated as of July
20, 1998 among the Partnership, Paramount and TransCanada (the "TransCanada
Consent")
9. The Partnership's agreement with NIMO (contained in the Mutual Release) to
terminate the existing License Agreement dated as of October 23, 1992
between the Partnership and NIMO (the "License Agreement")
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B-4
<PAGE>
ATTACHMENT C
ANALYSIS OF GAS CONTRACT MODIFICATIONS
Volume
Pace has determined that the Revised Paramount Contract total firm volume of
16,400 Mcf per day ("Revised MDQ") is sufficient to meet the maximum fuel
requirements of Unit 1. The Revised MDQ reflects a 6,600 Mcf reduction in the
original quantity of 23,000 Mcf, which is due to a long-term assignment of 6,000
Mcf of Selkirk transportation capacity on TransCanada PipeLines to Paramount.
Pace reviewed the long-term assignment and we find that the long-term assignment
would not likely introduce additional project risk.
The primary reasons for this finding are that under the Amended PPA it is
Selkirk's option whether to run Unit 1 (except for the Call Option discussed
directly below) and that availability requirements have been struck from the
agreement. Therefore, Pace concludes that Selkirk can be expected to lower
electrical output of Unit 1 to match the available gas supply, without incurring
penalty or losses in capacity revenues.
The NiMo Call Option creates an obligation for Unit 1 to generate certain
specified amounts of electricity. The Call Option exists only during the first
two years of the Amended PPA or until the SC-6 period expires, whichever occurs
sooner. The Independent Engineer has calculated the maximum net incremental fuel
requirement under the Unit 1 Call Option to be approximately 9,800 MMBtu/day
based on winter ambient conditions and full load electric generation of Unit 2.
Pace finds that Selkirk's firm gas supply under the Revised Paramount Contract
is more than sufficient to meet the maximum fuel requirement of the Call Option.
Additional supporting reasons for this finding include the following sources
available to Selkirk to supplement the firm contract gas supply:
1. Selkirk could reliably acquire spot natural gas supplies during summer and
shoulder periods to supplement the firm contract supply and spot gas
supplies during these periods can be relied upon over the long-term.
2. Selkirk can expect a maximum of 2% tolerance in Tennessee Gas Pipeline
daily delivery tolerances for long-term planning purposes. Based on
Selkirk's supply of 70,000 Mcf of firm capacity on Iroquois, this
flexibility would provide an additional 1,400 Mcf/day.
3. The NiMo inadvertent account established by separate contract can be used
to lower electric output by 5 MW without penalty or reduction in revenues.
Based on verification by the Independent Engineer, this provision results
in fuel savings of 1,000 Dt/day.
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C-1
<PAGE>
Price
The Revised Paramount Contract price is based on a published Empress, Alberta
monthly spot price index. The index is identical to the gas price component in
the Amended PPA except that the revenue index is multiplied by 105 percent,
which benefits the project (the gas price component in the Amended PPA under the
Call Option is discussed directly below). The Amended PPA price components have
been verified by the Independent Engineer. Pace finds that the use of this
identical gas price index creates strong linkage between Selkirk's gas cost and
NiMo electric sales revenue. In addition, corresponding to the fixed nature of
the Amended PPA, gas contract price re-determination provisions have been
removed under the Revised Paramount Contract. For these reasons and due to a
potential, slight de-linkage risk under the original Paramount Contract index,
linkage may be improved under the Revised Paramount Contract.
The Amended PPA gas price component under the Call Option is based on published
New York market area spot gas index prices. Pace finds the use of the New York
indices beneficial to Selkirk because the New York indices should always be
higher than the Empress, Alberta index used in the gas supply contract and the
use of the New York indices should approximate the resale prices at which
Selkirk would have resold the Paramount gas supply if NiMo had not exercised the
Call Option.
Supply Security
Under the Revised Paramount Contract, assurance of supply is derived from
dedicated reserves and liquidated damages that materially obligate Paramount to
perform. These same factors were also the primary elements of supply security
under the original Paramount Contract. Pace finds that although the dedicated
reserve provisions have been modified under the Revised Paramount Contract so
that Paramount may produce for any purpose from the dedicated lands, the supply
security under the Revised Paramount Contract is sufficient due to the following
factors:
1. The Revised Paramount Contract spot-market, production-area-based natural
gas pricing terms make a SAP claim highly unlikely.
2. The liquidated damages provided in the event Paramount fails to deliver the
nominated quantity up to the Revised MDQ are large and the Revised
Paramount Contract also requires Paramount to make available to the project
its transportation rights on NOVA, which provides access to alternative gas
supplies.
3. The current reserve and deliverability status of the dedicated lands
indicates far greater natural gas supply capability than is required to
meet the reserve dedication contract requirements.
4. The Revised Paramount Contract permits Paramount, under certain conditions,
to deliver other gas supplies ("Alternate Sources"), which gives Paramount
more flexibility to fulfill the Selkirk contract and lowers the risk of a
SAP claim.
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C-2
<PAGE>
Pace finds that the risk of a SAP claim is significantly reduced under the
Revised Paramount Contract because the contract commodity price is set to equal
a monthly spot market price near the Western Canadian production area applicable
to Paramount's gas supply. The potential for a SAP claim is nearly ruled out for
practical purposes since the market-set price for natural gas in the production
area should permit producers to fully recover all finding, development, and
replacement costs. While this may not be true at certain times due to short-term
market volatility and market disruptions, it is likely over the long run and the
SAP claim requires a determination five years in the future.
Security of supply is enhanced by the significant liquidated damages Paramount
faces in the event Paramount fails to deliver. The project has an additional
remedy in the event of Paramount delivery failure under the Revised Paramount
Contract to use Paramount's NOVA transportation to acquire supply at the AECO-C
market hub and deliver this gas to Empress. Under this scenario, AECO-Empress
basis pricing risk would exist, namely that gas prices at AECO would diverge
from prices at Empress to the detriment of the project. Pace finds that since
Selkirk would only be charged with the commodity cost portion of the NOVA
transportation, AECO-Empress basis pricing risk is sufficiently mitigated.
In addition, Pace finds that the current status of the reserves and
deliverability capability of the dedicated lands exceed the contract
requirements. Pace reviewed the August 21, 1997 McDaniel reserve report and the
Gilbert Lausten October 1, 1997 audit of the McDaniel report. In summary,
approximately 98 Bcf of reserves remained available to serve the Selkirk
contract as of November 1, 1997. The total contract requirements based on the
Revised MDQ from November 1, 1997 to the end of the primary term on November 1,
2007 are approximately 60 BCF, well under the estimated remaining reserves.
Similarly, the deliverability based on the 1997 reserve report was adequate and
under the Revised MDQ the amount of excess deliverability from currently
producing fields would increase and extend into 2002.
Pace also examined whether Paramount could rapidly deplete the reserves in the
dedicated lands by maximizing production and selling gas to other parties. The
McDaniel's report indicated the maximum possible production from the dedicated
lands to be approximately 21 Bcf from November 1, 1997 through October 31, 1998.
McDaniel's estimated maximum production declines over time consistent with
normal field depletion characteristics. Therefore, it would take more than four
and one-half years to fully deplete the remaining reserves even at the maximum
possible production rates providing ample advance notice of a reserve deficiency
that Paramount would be required to cure.
Finally, in the unlikely event that the market-set price at Empress falls below
Paramount's replacement costs, the Alternate Sources provision further enhances
supply security. Pace believes that Paramount could be expected to serve the
contract even in the case of an extended collapse in Empress spot market prices
by acquiring "low" priced alternative gas supply in the marketplace.
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C-3
<PAGE>
PARAMOUNT FINANCIAL AND MARKET POSITION
Paramount's sound financial condition, operating record, and growing asset base
provide additional comfort that Paramount can fulfill the Revised Paramount
Contract. Paramount boasts record operational and financial results in its 1997
Annual Report and its 1998 First Quarter Report. Increased production coupled
with strong commodity prices resulted in substantial increases in revenue. In
1997, Paramount's revenues increased 28 percent to $128 million. Production for
the first quarter 1998 rose 63 percent or 204 MMcf per day compared to the same
period for 1997. Finally, Paramount's proven gas reserves have increased each
year since 1993 and reached 481.7 Bcf in 1997.
In addition, trends in Paramount's gas sales portfolio indicate that Paramount
will likely have market incentives to perform under the Revised Paramount
Contract. Selkirk's share of Paramount's total gas sales volume has been
declining over the past several years and sales to Selkirk represented 11.1
percent of 1997 total Paramount gas sales. A growing share of Paramount's gas
sales is comprised of spot market volumes. For example, spot market sales
represented 38 percent of total sales in 1997 compared to 23 percent of sales in
1996. Spot market sales now represent an important component of Paramount's
total marketing portfolio and much of the spot volume is sold at Alberta spot
prices similar in nature to the pricing in the Revised Paramount Contract.
REGULATORY APPROVALS
Finally, the required Canadian and U.S. government regulatory approvals
pertaining to the Revised Paramount Contract have been obtained. The National
Energy Board (Canada) provided its approval in a July 7, 1998 letter and the
Department of Energy (United States) acknowledged Selkirk Cogen Partners, L.P.
had met the notification requirements related to amendments to arrangements to
import natural gas in correspondence dated July 15, 1998.
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C-4
PG&E 7500 Old Georgetown Road
U.S. Generating Company 13th Floor
Bethesda, MD 20814-6161
301.718.6800
Fax: 301.913.5854
FOR IMMEDIATE RELEASE Contact: Lisa Donnellan
Investor Relations
(301) 280-6979
SELKIRK COGEN PARTNERS CLOSE AMENDED AND RESTATED
POWER PURCHASE AGREEMENT WITH NIAGARA MOHAWK
(BETHESDA, MD, AUGUST 31, 1998) - Selkirk Cogen Partners, L.P., today announced
that it has satisfied the necessary conditions under its Trust Indenture to
consummate the transactions contemplated by the Master Restructuring Agreement,
dated as of July 9, 1997, as amended, between Niagara Mohawk Power Corporation
and certain independent power producers, including Selkirk Cogen. The Amended
and Restated Power Purchase Agreement, dated as of July 1, 1998 between Selkirk
Cogen and Niagara Mohawk, became effective with the closing of this transaction
on August 31, 1998.
Selkirk Cogen Partners, L.P., is a Delaware limited partnership whose partners
include affiliates of U.S. Generating Company (USGen). USGen is a wholly owned
indirect subsidiary of San Francisco-based PG&E Corporation, which provides a
full range of energy services throughout North America through its unregulated
affiliates.
--USGen--
U.S. GENERATING COMPANY IS NOT THE SAME AS PACIFIC GAS AND ELECTRIC COMPANY, THE
REGULATED CALIFORNIA UTILITY. U.S. GENERATING COMPANY IS NOT REGULATED BY THE
CALIFORNIA PUBLIC UTILITIES COMMISSION (CPUC). CALIFORNIA CUSTOMERS DO NOT HAVE
TO BUY PRODUCTS OF U.S. GENERATING COMPANY TO CONTINUE TO RECEIVE QUALITY
REGULATED SERVICES FROM THE CALIFORNIA UTILITY.
EDITORS: PLEASE NOTE THAT PG&E CORPORATION IS THE PROPER NAME FOR THE ENERGY
SERVICES HOLDING COMPANY TRADING ON THE NYSE UNDER THE STOCK SYMBOL PCG. PLEASE
DO NOT USE PACIFIC GAS AND ELECTRIC OR PACIFIC GAS AND ELECTRIC CORPORATION WHEN
REFERRING TO PG&E CORPORATION. EFFECTIVE JANUARY 1, 1997, THE PACIFIC GAS AND
ELECTRIC COMPANY, A REGULATED CALIFORNIA UTILITY, BECAME ONE OF FIVE LINES OF
BUSINESS MANAGED BY PG&E CORPORATION. THE FOUR OTHER NON-REGULATED SUBSIDIARIES
ARE U.S. GENERATING, PG&E GAS TRANSMISSION, PG&E ENERGY TRADING AND PG&E ENERGY
SERVICES.
