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
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
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
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")
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
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
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:
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.
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 $6.70/MWh adjusted to reflect changes since July 1, 1998 in
CPI. For purposes of this report we have assumed that the rate of general
inflation is the same as contained in the Existing PPA Case, which is 3.1
percent per year.
The pricing components are summarized for each of the first five years of the
Amended PPA in Table 2.
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 6
Table 2
Fixed Contract Price ($/MWh)
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
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 3
Slater Forecast of Locational Based Market Price
Year ($/MWh)
1998 $26.20
1999 25.80
2000 26.90
2001 28.60
2002 29.80
2003 31.10
2004 32.20
2005 33.50
2006 34.90
2007 35.90
Power Sales to NiMo and the Marketplace. From the effective date of the Amended
PPA until an ISO/PE is established and fully functioning, the Partnership will
have the option to sell and deliver energy and capacity to NiMo up to a
specified Monthly Contract Quantity, plus up to 5% of the Monthly Contract
Quantity. NiMo will be required to take and pay for such energy and capacity as
the Partnership delivers to it under the Sale Option at the Market Energy Price,
and, if applicable, the Market Capacity Price.
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 7
For any time-period during which the Partnership does not sell to NiMo, it may
sell such energy and associated capacity to third parties, provided that it
first offers NiMo the opportunity to purchase that energy and capacity at the
Market Energy Price, and, if applicable, the Market Capacity Price. The
Partnership is free to sell energy and capacity in excess of the Monthly
Contract Quantity to third parties without giving NiMo a right of first refusal.
In the Amended PPA Case, Selkirk receives revenues from the exercise of the Sale
Option. Additionally, there is a market for the energy generated from Phase I
which is in excess of the Monthly Contract Quantity. Under Slater's revised
dispatch for the Amended PPA Case, in 1998 Phase I will generate approximately
624,892 MWh assuming capacity of 79.9 MW, availability of 93 percent and a
dispatch of 96 percent. For purposes of this analysis, we have assumed that all
of Phase I's energy not sold to NiMo is sold to the marketplace at the Slater
forecasted Phase I Market Price.
Total revenues from projected Phase I energy sales over the term of the Bonds
are shown in Table 4.
Table 4
Delivered Energy Revenues
Total Slater Total
Delivered Market Price Revenue
Year Energy Sales ($/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
(1) - Year 2012 is a partial year due representing operations through April 16,
2012.
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.
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 9
Table 5
Dispatch Factors
At 100% Availability
Existing PPA Case (%) Amended PPA Case (%)
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
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.
Selkirk Cogen Partners, L.P.
August 27, 1998
Page 10
Table 6
Major Maintenance
Schedule of Deposits and Withdrawals
($000)
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 $1,684,810 on January 1, 1998.
EXISTING PPA BASE CASE
1998 1999 2000 2001 2002 2003 2004 2005
----- ----- ----- ----- ----- ----- ----- ----
PERFORMANCE
Unit 1
DMNC (kW) (1) 79,900 79,900 79,900 79,900 79,900 79,900 79,900 79,900
Availability Factor (2) 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0% 93.0%
Capacity Factor (3) 28.8% 41.8% 42.0% 55.8% 64.1% 62.3% 68.1% 67.9%
Energy Sales to
Niagara Mohawk (MWh)
Existing PPA Energy
Sales (MWh) (4) 201,747 292,803 293,666 390,619 448,987 436,132 476,445 475,070
Amended PPA Energy
Sales (MWh) (5) -- -- -- -- -- -- -- --
Fixed Energy
Sales (MWh) (6) -- -- -- -- -- -- -- --
Delivered Capacity
Sales (kW) (7) -- -- -- -- -- -- -- --
Unit 2
DMNC (kW) (1) 265,000 265,000 265,000 265,000 265,000 265,000 265,000 265,000
Availability Factor (2) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (3) 84.6% 86.5% 87.4% 87.4% 87.4% 88.3% 88.3% 89.2%
Energy Sales to
Con Ed (MWh) 1,964,833 2,007,547 2,034,946 2,028,904 2,028,904 2,050,260 2,056,366 2,071,617
Steam Sales (Mlbs) (8) 1,381,890 1,446,453 1,517,164 1,581,647 1,652,402 1,725,352 1,805,495 1,878,105
Contract Fuel Purchased
at Facility (BBtu)(9) 26,021,580 26,021,580 26,092,872 26,021,580 26,021,580 26,021,580 26,092,872 26,021,580
Contract Fuel
Purchased (BBtu) (10) 28,360,172 28,360,172 28,437,871 28,360,172 28,360,172 28,360,172 28,437,871 28,360,172
Fuel Required for
GE Plant (BBtu) (11) -- -- -- -- -- -- -- --
Fuel Consumption at
the Facility (BBtu)(12) 19,414,148 20,388,474 20,677,947 21,375,694 21,860,236 22,006,053 22,417,743 22,582,160
Fuel for Resale (BBtu) (13) 6,607,432 5,633,106 5,414,925 4,645,886 4,161,344 4,015,527 3,675,129 3,439,420
Spot Market Fuel
Purchased (BBtu) (14) -- -- -- -- -- -- -- --
COMMODITY PRICES
Electricity Price
Niagara Mohawk Contract
Existing PPA Fixed
Component ($ /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
1
EXISTING PPA BASE CASE
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
2
EXISTING PPA BASE CASE
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
3
EXISTING PPA BASE CASE
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
4
AMENDED PPA CASE
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
5
AMENDED PPA CASE
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
6
AMENDED PPA CASE
z
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
7
AMENDED PPA CASE
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
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.
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.
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.
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
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
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
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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")