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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MARCH 1, 2001.
REGISTRATION NO. 333- 50350
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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AMENDMENT NO. 3 TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
PPL MONTANA, LLC
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 4911 54-1928759
(STATE OR OTHER JURISDICTION OF (PRIMARY STANDARD INDUSTRIAL (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) CLASSIFICATION CODE NUMBER) IDENTIFICATION NUMBER)
PAUL FARR
CHIEF FINANCIAL OFFICER
303 NORTH BROADWAY, SUITE 400 PPL MONTANA, LLC
BILLINGS, MONTANA 59101 BILLINGS, MONTANA 59101
(406) 869-5100 (406) 869-5100
(ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, (NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE
INCLUDING AREA CODE, OF REGISTRANT'S PRINCIPAL NUMBER, INCLUDING AREA CODE, OF AGENT FOR SERVICE OF
EXECUTIVE OFFICES) PROCESS)
WITH A COPY TO:
DAVID P. FALCK, ESQ.
PILLSBURY WINTHROP LLP
ONE BATTERY PARK PLAZA
NEW YORK, NEW YORK 10004
(212) 858-1438
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE
PUBLIC: As soon as practicable after this Registration Statement becomes
effective.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ] ----------
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ] ----------
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CALCULATION OF REGISTRATION FEE
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TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED MAXIMUM PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED(1) OFFERING PRICE PER UNIT AGGREGATE OFFERING PRICE REGISTRATION FEE(2)
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8.903% Pass Through
Certificates due 2020...... $338,000,000 100% $338,000,000 $89,232
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(1) Equals the aggregate principal amount of the securities being registered.
(2) This entire amount has been previously paid.
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THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
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THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS
NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO
BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.
SUBJECT TO COMPLETION, DATED MARCH [ ], 2001
PRELIMINARY PROSPECTUS
PPL MONTANA, LLC
EXCHANGE OFFER
8.903% PASS THROUGH CERTIFICATES DUE 2020
The Exchange Offer............ We are offering to exchange pass through
certificates registered with the Securities and
Exchange Commission for existing pass through
certificates that we previously offered in an
offering exempt from the SEC's registration
requirements. The terms and conditions of the
exchange offer are summarized below and more
fully described in this prospectus.
New Certificates.............. The new certificates will represent the same
fractional undivided interest in a pass through
trust as the old certificates they are
replacing. The new certificates will have the
same material financial terms as the old
certificates, which are described more fully in
this prospectus. The new certificates will not
contain terms with respect to transfer
restrictions or interest rate increases.
Expiration Date............... 5:00 p.m. (New York City time) on
[ ], 2001.
Withdrawal Rights............. Any time before 5:00 p.m. (New York City time)
on the expiration date.
Integral Multiples............ Old certificates may only be tendered in
integral multiples of $1,000.
Expenses...................... Paid for by PPL Montana, LLC.
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INITIAL PRINCIPAL FINAL PRINCIPAL INTEREST
PRINCIPAL AMOUNT INTEREST RATE DISTRIBUTION DATE DISTRIBUTION DATE DISTRIBUTION DATES
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$338,000,000 8.903% January 2, 2001 July 2, 2020 January 2 and July 2
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YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 14 OF THIS
PROSPECTUS.
The certificates represent interests in a pass through trust only and do
not represent interests in or obligations of PPL Corporation, PPL Montana, LLC,
or any other affiliate of PPL Corporation.
We do not intend to apply to list the certificates on any national
securities exchange or the Nasdaq Stock Market.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED THAT
THIS PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this prospectus is [ ], 2001.
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TABLE OF CONTENTS
PAGE
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PROSPECTUS SUMMARY.......................................... 1
RISK FACTORS................................................ 14
THIS EXCHANGE OFFER......................................... 23
RATIO OF EARNINGS TO FIXED CHARGES.......................... 31
USE OF PROCEEDS............................................. 32
SELECTED FINANCIAL AND OPERATING DATA....................... 33
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................. 34
ABOUT US.................................................... 39
BUSINESS.................................................... 41
REGULATION.................................................. 51
MANAGEMENT.................................................. 59
RELATIONSHIPS AND RELATED TRANSACTIONS...................... 65
SUMMARY OF INDEPENDENT ENGINEER'S REPORT.................... 66
SUMMARY OF INDEPENDENT MARKET CONSULTANT'S REPORT........... 68
SUMMARY OF INDEPENDENT FUEL CONSULTANT'S REPORT............. 71
DESCRIPTION OF OUR PRINCIPAL CONTRACTUAL ARRANGEMENTS....... 72
DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES.......... 82
DESCRIPTION OF THE LEASE DOCUMENTS.......................... 105
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES............... 123
ERISA CONSIDERATIONS........................................ 128
PLAN OF DISTRIBUTION........................................ 130
INDEPENDENT CONSULTANTS..................................... 131
LEGAL MATTERS............................................... 131
IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS
PROSPECTUS................................................ 131
WHERE YOU CAN FIND MORE INFORMATION......................... 131
INDEX TO FINANCIAL STATEMENTS............................... F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS.................... F-3
APPENDIX A: INDEPENDENT ENGINEER'S REPORT................... A-1
APPENDIX B: INDEPENDENT MARKET CONSULTANT'S REPORT.......... B-1
APPENDIX C: INDEPENDENT FUEL CONSULTANT'S REPORT............ C-1
Until [ ], 2001, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unused
allotments or subscriptions.
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PROSPECTUS SUMMARY
The following summary highlights selected information from this prospectus
and may not contain all of the information that is important to you. This
prospectus includes specific terms of the certificates, as well as information
regarding our business and detailed financial data. We encourage you to read
this prospectus in its entirety. You should pay special attention to the "Risk
Factors" section beginning on page 14 of this prospectus.
PPL MONTANA
We are an indirect wholly owned subsidiary of PPL Corporation. We were
formed to acquire, own, lease and operate interests in thirteen generating
facilities with an aggregate capacity of approximately 1,260 net megawatts. When
we refer to MW in this prospectus, we mean net megawatts. We refer to these
generating facilities, together with a storage reservoir that we also acquired,
as the Montana portfolio.
We sell all of the energy generated by these generating facilities in the
region referred to as the Western Systems Coordinating Council, which covers a
large portion of the western United States. Within the Western Systems
Coordinating Council, our primary regional market is the Northwest (Montana,
Oregon, Washington and Idaho), and Montana is our single most important market.
Our energy marketing plan, which targets both wholesale and retail customers,
will be implemented on our behalf by our affiliate PPL EnergyPlus, LLC.
The Montana portfolio consists of the following generating assets:
- eleven hydroelectric generating facilities and a storage reservoir, which
we wholly own;
- the J.E. Corette coal-fired generating facility, which we wholly own; and
- our leasehold interest in an undivided joint ownership interest in units
1, 2 and 3 of the Colstrip coal-fired generating facility.
The hydroelectric generating facilities are primarily located in the
Columbia River and Missouri-Madison River basins and together generate up to 577
MW of energy in the summer. The Corette facility is located near Billings,
Montana and can generate 154 MW of energy. The Colstrip facility, located in
Colstrip, Montana, is the second largest coal-fired generating facility west of
the Mississippi River and can generate 2,094 MW of energy. We lease 529 MW of
the energy generation capacity of the Colstrip facility, and we are the operator
of the entire facility.
Our principal executive offices are located at 303 North Broadway, Suite
400, Billings, Montana 59101, and our main telephone number is (406) 869-5100.
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SUMMARY OF THIS EXCHANGE OFFER
On July 20, 2000, we completed the offering of $338 million principal
amount of 8.903% pass through certificates due 2020, which we refer to as the
old certificates. In connection with that offering, we agreed to deliver to you
this prospectus and to use our best efforts to complete the exchange offer by
April 16, 2001, which is 270 days after the date of original issuance of the old
certificates.
THIS EXCHANGE OFFER........ We are offering to exchange up to $338 million
aggregate principal amount of old certificates that
were issued on July 20, 2000 for up to $338 million
aggregate principal amount of new certificates that
have been registered under the Securities Act of
1933, which we refer to as the Securities Act. Old
certificates may be exchanged in denominations of
integral multiples of $1,000 principal amount. We
will issue the new certificates promptly after the
expiration of the exchange offer.
The form and terms of the new certificates that we
are offering in the exchange offer, which we refer
to as the new certificates, are identical in all
material respects to the form and terms of the old
certificates which were issued on July 20, 2000 in
an offering that was exempt from the SEC's
registration requirements, except that the new
certificates that we are offering in the exchange
offer have been registered under the Securities
Act. The new certificates that we are offering in
the exchange offer will evidence the same
obligations as, and will replace, the old
certificates and will be issued under the same pass
through trust agreement.
If you wish to exchange an outstanding old
certificate, you must properly tender it in
accordance with the terms described in this
prospectus.
As of this date, there are $338 million principal
amount of old certificates outstanding. The
exchange offer is not contingent upon any minimum
aggregate principal amount of existing pass through
trust certificates being tendered for exchange. We
will arrange for the pass through trustee to issue
the registered pass through trust certificates on
or promptly after the expiration of the exchange
offer.
REGISTRATION RIGHTS
AGREEMENT.................. We are making this exchange offer in order to
satisfy our obligation under the registration
rights agreement, entered into July 13, 2000, to
cause our registration statement to become
effective under the Securities Act. You are
entitled to exchange your old certificates for
registered new certificates with substantially
identical terms. After the exchange offer is
complete, you will generally no longer be entitled
to any registration rights with respect to your
certificates.
RESALES OF THE NEW
CERTIFICATES............... Based on an interpretation by the SEC staff set
forth in no-action letters issued to third parties,
we believe that the new certificates issued
pursuant to the exchange offer in exchange for old
certificates may be offered for resale, resold and
otherwise transferred by you without compliance
with the registration and prospectus delivery
requirements of the Securities Act provided that:
- you acquire any new certificate in the ordinary
course of your business;
- you are not participating, do not intend to
participate, and have no arrangement or
understanding with any person to participate, in
the distribution of the new certificates;
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- you are not a broker-dealer who purchased old
certificates for resale pursuant to Rule 144A or
any other available exemption under the
Securities Act; and
- you are not an "affiliate" of our company, within
the meaning of Rule 405 under the Securities Act.
If our belief is inaccurate and you transfer any
new certificate without delivering a prospectus
meeting the requirements of the Securities Act
without an exemption from registration of your
certificates from such requirements, you may incur
liability under the Securities Act. We do not
assume or indemnify you against this liability.
Each broker-dealer that is issued new certificates
for its own account in exchange for old
certificates must acknowledge that it will deliver
a prospectus meeting the requirements of the
Securities Act in connection with any resale of the
new pass through trust certificates. The letter of
transmittal states that, by making this
acknowledgment and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the
Securities Act. A broker-dealer who acquired old
certificates for its own account as a result of
market-making or other trading activities may use
this prospectus for an offer to resell, resale or
other retransfer of the new certificates. We have
agreed that, for a period of 180 days following the
completion of this exchange offer, we will make
this prospectus and any amendment or supplement to
this prospectus available to any broker-dealers for
use in connection with these resales. We believe
that no registered holder of the existing pass
through trust certificates is an "affiliate" of our
company, within the meaning of Rule 405 under the
Securities Act.
EXPIRATION DATE............ This exchange offer will expire at 5:00 p.m., New
York City time, [ ], 2001, unless we
decide to extend the expiration date. We do not
currently intend to extend the expiration date,
although we reserve the right to do so, and we have
agreed to use our reasonable best efforts to
complete the exchange offer promptly but no later
than April 16, 2001.
CONDITIONS TO THIS EXCHANGE
OFFER.................... This exchange offer is not subject to any
conditions other than that it does not violate
applicable law or any applicable interpretation of
the SEC staff.
WITHDRAWAL RIGHTS.......... You may withdraw the tender of your old
certificates at any time prior to 5:00 p.m. New
York City time on [ ], 2001.
MATERIAL U.S. FEDERAL
INCOME TAX CONSEQUENCES.... The exchange of old certificates for new
certificates pursuant to the exchange offer will
not constitute a taxable event for United States
federal income tax purposes. For a discussion of
other U.S. federal income tax consequences
resulting from the exchange, acquisition, ownership
and disposition of the new certificates, see
"Material U.S. Federal Income Tax Consequences."
USE OF PROCEEDS............ We will not receive any proceeds from the issuance
of the new certificates offered in this exchange
offer. In consideration for issuing the new
certificates as contemplated in this prospectus, we
will receive in exchange old certificates in like
principal amount. We will pay all registra-
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tion expenses incident to this exchange offer. Each
holder of certificates will pay all underwriting
discounts and commissions and transfer taxes
incurred in the sale or disposition of the
certificates issued in this exchange offer.
EXCHANGE AGENT............. The Chase Manhattan Bank is serving as exchange
agent in connection with the exchange offer.
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SUMMARY OF OUR BUSINESS
OUR ACQUISITION OF THE MONTANA PORTFOLIO, THE COLSTRIP FACILITY AND THE LEASE
TRANSACTIONS
The acquisition
In June 1997, the Montana state legislature enacted a bill which
deregulated the energy generating business and initiated customer choice for
competitive energy supplies effective July 1, 1998. In response to this
legislation, in March 1998, The Montana Power Company, or MPC, initiated an
auction to divest its generating assets.
PPL Global, LLC, a direct subsidiary of PPL Energy Funding Corporation, was
selected as the winning bidder in this auction process. In October 1998, PPL
Global entered into an asset purchase agreement with MPC under which PPL Global
agreed to acquire the Montana portfolio for a purchase price of approximately
$760 million plus transaction expenses. PPL Global subsequently assigned its
interests in the asset purchase agreement to us, and we closed the acquisition
of the Montana portfolio on December 17, 1999. We have an obligation under this
asset purchase agreement to acquire the portion of MPC's interest in a
transmission system known as the Colstrip transmission system that is related to
the interests in the Colstrip facility that we acquired from MPC. Negotiations
to complete this acquisition are ongoing. On July 20, 2000, we sold our
interests in the Colstrip facility and leased the interests back, as described
below.
Our interests in the Colstrip facility
The most significant asset in the Montana portfolio is our interest in the
Colstrip facility. The Colstrip facility consists of four coal-fired generating
units. Colstrip units 1 and 2 are twin 307 MW generating units and Colstrip
units 3 and 4 are twin 740 MW generating units.
We hold a 50% leasehold interest in Colstrip units 1 and 2 and a 30%
leasehold interest in Colstrip unit 3. Puget Sound Energy, Inc. owns the other
50% undivided interest in Colstrip units 1 and 2. Colstrip units 1 and 2 are
governed by an ownership agreement and an operation agreement. These agreements
provide for an owners' committee and an operator. Most of the responsibility for
operating Colstrip units 1 and 2 is vested in us, as the operator. The role of
the owners' committee in operating Colstrip units 1 and 2 is limited to
scheduling planned outages, reviewing the annual operation and maintenance costs
that we incur and approving the annual budget that we propose. These agreements
provide the owners of Colstrip units 1 and 2 with rights of first refusal in
respect of transfers and assignments of ownership interests in Colstrip units 1
and 2.
Puget, Portland General Electric Company, Avista Corporation and PacifiCorp own
25%, 20%, 15% and 10%, respectively, of the undivided ownership interests in
each of Colstrip units 3 and 4. In addition, MPC owns a 30% leasehold interest
in Colstrip unit 4. We refer to these owners and ourselves as the project users.
Colstrip units 3 and 4 are governed by an ownership and operation
agreement. This agreement is independent of the agreements governing Colstrip
units 1 and 2. Pursuant to this agreement, each project user has a project share
in Colstrip units 3 and 4 equal to the sum of (1) any undivided interests in
Colstrip units 3 and 4 owned by that project user, and (2) any undivided
interests in Colstrip units 3 and 4 leased to that project user by a third-party
owner. This agreement provides for a project committee and an operator. Each of
Puget, Portland, Avista and PacifiCorp is able to appoint one member to the
project committee. Under the terms of a vote sharing agreement between MPC and
us, MPC and we jointly control the remaining vote on the project committee. As
with Colstrip units 1 and 2, most of the responsibility for operating Colstrip
units 3 and 4 is vested in us, as the operator. Some types of major decisions
must be approved by 55%, 65% or 85% of the total project shares. Each project
user is required to contribute its project share of the costs of operation for
Colstrip units 3 and 4. This ownership and operation agreement also provides the
owners of Colstrip units 3 and 4 rights of first refusal in respect of transfers
and assignments of ownership interests in Colstrip units 3 and 4.
Under a separate agreement with MPC, our 30% leasehold interest in Colstrip
unit 3 entitles us to a 15% share of the combined energy generation capacity of
Colstrip units 3 and 4 and obligates us to cover 15% of the
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operations and maintenance costs of Colstrip units 3 and 4. Our leasehold
interest provides us approximately 307 MW from Colstrip units 1 and 2 and 222 MW
from Colstrip units 3 and 4.
The Colstrip facility is owned as indicated below:
UNITS 1 & 2 -- 2 X 307 MW UNIT 3 -- 740 MW UNIT 4 -- 740 MW
[Pie Chart] [Pie Chart] [Pie Chart]
The lease transactions
On July 20, 2000, we sold our interests in the Colstrip facility to three
owner lessors under four separate lease transactions. We refer to these
interests as the leased assets. Each owner lessor is beneficially owned by an
institutional investor. We refer to these investors as owner investors. We
entered into two leases that relate to Colstrip units 1 and 2 and two leases
that relate to Colstrip unit 3. Each owner lessor issued a lessor note in
connection with each lease to the pass through trust. The pass through trust
purchased the lessor notes with the proceeds of the old certificates. Each owner
lessor used the proceeds from the sale of its lessor note to fund a portion of
the purchase price of its portion of the leased assets.
Each lessor note is secured by, among other things, the interest in the
related leased assets purchased with the proceeds of such lessor note, and by
the applicable owner lessor's interest in the related lease documents other than
the tax indemnity agreement. The lessor notes are not secured by any of the
other assets included in the Montana portfolio. Our obligations under each
lease, however, are our general unsecured obligations. Revenues generated from
the entire Montana portfolio support our obligation to pay rent.
The rent payment under each lease is in an amount that is sufficient to pay
the principal of, premium, if any, and interest on the lessor note issued by the
applicable owner lessor. Each owner lessor has assigned its right to receive
rent payments to the trustee under the indenture for the owner lessor's lessor
note.
Because each owner lessor's right to receive rent under its lease has been
assigned to the applicable indenture trustee, we pay all rent directly to the
indenture trustees. From the rent it receives from us, each indenture trustee
pays principal, premium, if any, and interest due on the lessor note issued
under its indenture to the pass through trust. The pass through trust
distributes the payments received by it as holder of the lessor notes to you.
After payment to the pass through trust, each indenture trustee distributes the
remaining balance, if any, of the rent received from us to the applicable owner
lessor who distributes such amounts to its owner investor.
The certificates offered to you represent interests in the pass through
trust that holds the lessor notes. Only the pass through trust is directly
liable to make distributions on the certificates. Our obligation is to make
payments under the leases. Neither we nor any of our affiliates is directly
liable to make distributions on the certificates.
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The following diagram illustrates the payment flows in the lease
transactions among us as lessee, the owner lessors, the indenture trustees, the
pass through trust and the certificate holders.
[Flow Chart]
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SUMMARY OF TERMS OF THE NEW CERTIFICATES
The form and terms of the new certificates are the same as the form and
terms of the old certificates except that the new certificates will be
registered under the Securities Act and, therefore, will not bear legends
restricting their transfer and, in general, will not be entitled to registration
under the Securities Act. The new certificates will evidence the same
obligations as the old certificates and both the old certificates and the new
certificates are governed by the same pass through trust agreement.
The certificates are not our direct obligations. Each certificate
represents a fractional undivided interest in a pass through trust formed
pursuant to a pass through trust agreement between us and The Chase Manhattan
Bank, as pass through trustee. The pass through trust was formed for the benefit
of the holders of the pass through trust certificates.
The property of the pass through trust consists solely of lessor notes
issued on a non-recourse basis by three owner lessors under four separate lease
transactions. Each owner lessor is beneficially owned by an institutional
investor. Each lessor note is secured by, among other things, the interest in
the related leased assets purchased with the proceeds of such note, and by the
applicable owner lessor's interest in the related lease documents other than the
tax indemnity agreement. The lessor notes are not secured by any of the other
assets included in the Montana portfolio. Our obligations under each lease,
however, are our general unsecured obligations. Revenues generated from the
entire Montana portfolio currently support our obligation to pay rent.
The lessor notes issued by the three owner lessors were issued in a single
series under four lease indentures between the three owner lessors and The Chase
Manhattan Bank, as lease indenture trustee. The pass through trust purchased all
the lessor notes issued by the three owner lessors so that all of the lessor
notes held in the pass through trust have an interest rate and maturity date
corresponding to the final distribution date applicable to the old certificates
issued on July 20, 2000. The pass through trustee will generally distribute any
amounts paid by the owner lessors in respect of the lessor notes to the holders
of the new certificates promptly after receipt. Distributions on the new
certificates therefore depend on the rental and other payments that we make
under the leases on Colstrip units 1, 2 and 3. PPL Corporation has no obligation
for and has not guaranteed our lease obligations, the pass through trust
certificates or the lessor notes issued by the owner lessors which are held by
the pass through trust.
The following summary contains basic information about the new
certificates. It does not contain all the information that may be important to
you. For a more complete description of the new certificates, please refer to
the section of this prospectus entitled "Description of the Pass Through
Certificates."
SECURITIES OFFERED............ $338,000,000 aggregate principal amount of
8.903% pass through certificates due 2020.
PASS THROUGH TRUST............ The new certificates will be offered by a pass
through trust. The pass through trust was
formed by a pass through trust agreement
between us and The Chase Manhattan Bank, as the
pass through trustee.
PASS THROUGH TRUST PROPERTY... The property of the pass through trust consists
solely of the lessor notes.
INTEREST...................... Interest on the lessor notes will accrue at a
rate of 8.903% per year. Interest on the lessor
notes and the resulting distributions on the
certificates will be payable semiannually in
arrears on January 2 and July 2 of each year,
beginning on January 2, 2001.
PAYMENT DATES................. Principal payments will be made on the lessor
notes and the resulting distributions will be
made on the certificates according to the
amortization schedule on page 105.
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AVERAGE LIFE OF THE
CERTIFICATES.................. The certificates will be paid off over varying
periods of time, but the average of the periods
is approximately 9.93 years.
RANKING....................... Rent payable by us under the leases is the
source of payment for the lessor notes and,
consequently, the certificates. Our obligation
to pay rent is our senior unsecured obligation
and ranks equally in right of payment with all
of our other existing and future senior
unsecured obligations. We currently have
approximately $70 million in senior unsecured
obligations, consisting of bank letters of
credit issued on our behalf.
LEASE DOCUMENTS............... The lease documents for each lease transaction
include a bill of sale, a lease, a site lease
and sublease, an assignment and reassignment of
the related ownership and operating
agreement(s), a participation agreement, a
lease indenture, a lessor note, a limited
liability company agreement relating to the
owner lessor, a guaranty of the parent of the
owner investor and a tax indemnity agreement
between us and the owner investor.
COLLATERAL FOR THE LESSOR
NOTES......................... The lessor note issued for each lease
transaction is secured by a first priority
security interest in the rights and interests
of the owner lessor in the following:
- the related lease under which the owner
lessor leases the related interest in
the leased assets to us, including its
right to receive rent;
- the related interest in the leased
assets;
- the related site lease and sublease,
participation agreement and other lease
documents (other than the tax indemnity
agreement);
- the related ownership and operating
agreement(s);
- the common facilities agreement for the
Colstrip facility; and
- its right to receive payments under a
rent reserve letter of credit issued on
our behalf in an amount equal to the
greater of (1) the next scheduled
payment under the related lease, or (2)
50% of the next twelve months of the
scheduled payments under the related
lease.
All of the property and rights described above
are referred to collectively as the
"collateral." The collateral does not include
any of our other generating assets. The
collateral also excludes customary excepted
payments and rights reserved to the owner
lessors and the owner investors.
NO CROSS COLLATERALIZATION OF
LESS OR NOTES OR CROSS DEFAULT
PROVISIONS.................. The lessor note issued in a lease transaction
will not be cross-collateralized with, or
generally cross-defaulted to, the lessor note
issued under the other lease transactions. The
covenants under each set of lease documents are
identical except that (1) we provide a separate
rent reserve letter of credit for each lease,
and (2) there are certain facility-specific
covenants, such as mainte-
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nance and insurance, which relate to the
applicable unit being leased. Thus, an event of
default under one lease may not necessarily
trigger an event of default under the other
leases. However, we are required to pay rent
under each lease pro rata without preference to
any lease, so a failure to pay rent under any
lease would trigger an event of default under
the other leases.
OPTIONAL REDEMPTION........... We may request, or with our consent the owner
investors may cause, the owner lessors to
redeem the lessor notes (and consequently cause
the pass through trust to redeem the
certificates) at a redemption price equal to:
- 100% of the principal amount of the
lessor notes being redeemed, plus
- accrued interest on the lessor notes
being redeemed, plus
- a make whole premium based on the rates
of comparable treasury securities plus
50 basis points.
We agree not to request that any lessor note be
redeemed or consent to a request from any owner
investor to cause the related owner lessor to
redeem its lessor notes unless all four lessor
notes are being redeemed.
MANDATORY REDEMPTION WITHOUT
PREMIUM..................... Upon receipt by the indenture trustees of
proceeds in connection with any of the
circumstances described below, one or all of
the lessor notes will be redeemed, in whole or,
in the case of a termination of the leases
relating to Colstrip units 1 or 2 under items
(2) or (3) below, in whole or in part, at a
redemption price equal to 100% of the principal
amount of the lessor notes being redeemed plus
accrued interest. The certificates will be
redeemed in whole or in part with the proceeds
of a redemption of the related lessor notes
under the following circumstances:
(1) Any owner investor or any owner lessor
is then subject to any public utility
regulation that renders it burdensome
to participate in the lease
transactions, which we refer to as a
regulatory event of loss, unless
either (a) we purchase the beneficial
interest in the owner lessor and waive
the regulatory event of loss, and the
lease between us and the owner lessor
remains in effect, or (b) we assume
the lessor note(s) issued by the owner
lessor;
(2) any event of loss, other than a
regulatory event of loss, occurs with
respect to one or more of the Colstrip
units, unless we elect to rebuild or
replace the damaged Colstrip unit or
units, and the event of loss results
in a termination or parallel partial
termination of the other lease related
to the damaged Colstrip unit or units;
(3) we elect to terminate all applicable
leases, in whole or in part, because
one or more of the Colstrip units are
then economically or technologically
obsolete as a result of:
- a change in law, regulation or
tariff of general application, or
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- the imposition by a governmental
authority of any conditions or
requirements (including requiring
significant capital improvements to
the affected Colstrip unit or
units) upon the availability,
continued effectiveness or renewal
of any license or permit required
for the ownership or operation of
the Colstrip unit or units; or
(4) we exercise our option to terminate
one or more of the leases (except in
circumstances where we assume the
applicable lessor notes) if:
- a change in law causes it to become
illegal for us to continue a lease
or to pay rent under a lease and
the other lease documents, and the
transactions contemplated by the
lease documents cannot be
restructured to comply with the
change in law, or
- one or more events outside of our
control occurs and causes us to
have burdensome indemnity
obligations under the lease
documents.
MANDATORY REDEMPTION WITH
PREMIUM....................... If we elect to terminate the applicable leases,
in whole or in part, because one or more of the
Colstrip units is:
- economically or technologically obsolete
for reasons other than the reasons in
item (3) above under "Mandatory
redemption without premium," or
- surplus to our needs or no longer useful
in our trade or business,
then the outstanding lessor notes will be
redeemed, in whole or in part, at a redemption
price equal to:
- 100% of the principal amount of the
lessor notes being redeemed, plus
- accrued interest on the lessor notes
being redeemed, plus
- a make whole premium based on the rates
of comparable treasury securities plus
50 basis points.
COVENANTS..................... The lease documents limit our ability to, among
other things:
- incur debt;
- sell assets;
- create liens;
- declare dividends or make other
distributions or similar payments;
- enter into transactions with affiliates;
- engage in any business other than
permitted businesses specified in the
lease documents; and
- engage in mergers, consolidations or
similar transactions.
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The lease documents also require us to, among
other things, provide the following items to
the indenture trustees and the rating agencies:
- annual audited financial statements and
no default certificates, and
- quarterly unaudited financial
statements.
CHANGE OF CONTROL............. It is an event of default under the leases if
PPL Corporation's direct or indirect beneficial
ownership in us is reduced to less than 50%,
unless Moody's and S&P confirm that the then
existing ratings for the certificates will not
be lowered as a result of the reduction in
ownership.
Upon the occurrence of an event of default
under the leases that is caused by a reduction
of PPL Corporation's interest in us, the
indenture trustees may accelerate the lessor
notes and require us to pay a premium equal to
1% of the principal amount of the outstanding
lessor notes in addition to principal and
accrued interest on the outstanding lessor
notes.
LEASE ASSIGNMENT.............. We may not assign any lease document without
the prior written consent of the applicable
indenture trustee, except that we may assign
all of the lease documents (1) in connection
with a merger, consolidation or sale of
substantially all our assets to the extent
permitted under the lease documents, or (2) if
the following conditions, among others, are
met:
- the certificates are rated at least Baa3
by Moody's and at least BBB- by S&P; and
- Moody's and S&P confirm that the
assignment will not result in a
downgrade of the then existing ratings
for the certificates.
If these conditions are met, we will not have
any further liability or obligation under the
lease documents.
GOVERNING LAW................. The certificates, the pass through trust
agreement, the lease indentures and the lessor
notes are governed by the laws of the State of
New York, except to the extent that the leases,
the site lease and subleases and the indentures
are required to be governed by the laws of the
State of Montana.
FORM, DENOMINATION AND
REGISTRATION OF
CERTIFICATES................ The certificates (other than certificates sold
to institutional accredited investors) were
issued in book-entry form and are represented
by one or more fully registered global
certificates. Each global certificate has been
deposited with, or on behalf of, the Depository
Trust Company, which we refer to as DTC, and
registered in its name or in the name of Cede &
Co., its nominee. The certificates sold to
institutional accredited investors are
represented by fully registered physical
certificates. The certificates were issued in
denominations of $100,000 or any integral
multiple of $1,000 in excess of $100,000.
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INDENTURE TRUSTEE............. The Chase Manhattan Bank acts as the indenture
trustee for the lessor notes under each of the
indentures.
RISK FACTORS.................. An investment in the new certificates involves
risks, including, without limitation, risks
related to the uncertainties associated with
the competitive market in which we operate, the
structure of the lease transactions and the
operation of our generating facilities. A
description of these risks begins on page 14.
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RISK FACTORS
In addition to the information contained elsewhere in this prospectus, you
should carefully consider the following risk factors in evaluating an investment
in the new certificates.
OUR REVENUES AND RESULTS OF OPERATIONS WILL DEPEND IN PART ON MARKET AND
COMPETITIVE FORCES THAT ARE OUTSIDE OF OUR CONTROL.
The markets for wholesale and retail energy transactions in the Western
Systems Coordinating Council have been, or are in the process of becoming,
deregulated. We and other owners of generating facilities will not be guaranteed
a specified rate of return on our capital investments or recovery of our costs.
Therefore, our revenues and results of operations will depend on the prices that
we can obtain for energy in the Montana market and adjacent markets. Among the
factors beyond our control that could influence prices are:
- fuel supply and price -- the prevailing market prices for natural gas,
fuel oil and coal, and the amount of water available from the river
systems in the Western Systems Coordinating Council;
- competition -- the extent of additional supplies of energy from our
current competitors or new market entrants, which may include the
construction of additional energy generation capacity in Montana or
elsewhere in the Western Systems Coordinating Council;
- regulation -- the regulatory and pricing structures developed for Western
Systems Coordinating Council energy markets as they continue to evolve;
- transmission -- future pricing for and availability of transmission
services, the effect of deregulation proposals and export energy
transmission constraints, each of which could limit our ability to sell
energy in markets adjacent to Montana;
- market structure -- the pace of the development of Northwest regional
markets for energy and capacity which does not yet exist except in the
context of bilateral contracts; and
- demand -- the rate of growth in energy usage as a result of factors such
as regional economic conditions and the implementation of conservation
programs.
IN OPERATING THE MONTANA PORTFOLIO, WE MAY ENCOUNTER EXPENSES AND OPERATING
PROBLEMS GREATER THAN WE ANTICIPATE.
Operation of the Montana portfolio involves risks including the energy
output and efficiency levels at which the Montana portfolio performs,
interruptions in fuel supply, increased prices for fuel supply and
transportation as existing contracts expire, disruptions in the delivery of
energy, facility shutdown due to a breakdown or failure of equipment or
processes, violation of permit requirements (whether through operations or
changes in law), operator error or catastrophic events such as fires,
explosions, floods or other similar occurrences affecting the Montana portfolio,
ourselves or third parties upon which our business may depend.
The generating facilities in the Montana portfolio, like other generating
facilities of similar age, will require additional capital expenditures. Except
for the Kerr and Cochrane facilities, initial construction of the hydroelectric
dams and generating facilities occurred before 1930. The units comprising the
Colstrip facility and the Corette facility are between 15 and 33 years old. All
generating facilities require continuing capital expenditures in order to keep
operations at optimal levels. The average capital expenditures we project to
make for these maintenance projects are approximately $15 million per year. Our
actual capital expenditure requirements could differ significantly from these
estimates. The lease documents and our existing working capital facility will
limit our ability to incur indebtedness to finance capital expenditures.
WE MAY NOT BE ABLE TO SUCCESSFULLY IMPLEMENT OUR MARKETING PLAN AND THE OTHER
ASPECTS OF OUR BUSINESS PLAN.
Our results of operations depend on our ability to implement our business
plan. Our business plan assumes, among other things, that the generating assets
included in the Montana portfolio will be maintained,
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available and dispatched at levels necessary to support our marketing plan. The
business plan also assumes that we can effectively execute our marketing plan.
We are relying on PPL EnergyPlus to implement our marketing plan by creating a
portfolio of wholesale and retail contracts that will provide a stable revenue
stream with satisfactory operating margins. We cannot assure you that PPL
EnergyPlus will successfully execute our marketing plan.
BECAUSE THE MONTANA PORTFOLIO WAS NOT OPERATED HISTORICALLY ON A COMPETITIVE
BASIS WE DO NOT KNOW IF WE CAN OPERATE IT SUCCESSFULLY IN A COMPETITIVE
ENVIRONMENT.
Substantially all of our business consists of owning or leasing and
operating the Montana portfolio. Although the assets included in the Montana
portfolio had a significant operating history at the time we acquired them, the
assets had all been operated as an integrated part of a regulated utility and
thus the energy generated by the assets was sold by MPC based upon rates set by
regulatory authorities. While owned by MPC, the Montana portfolio was generally
operated at lower average output than planned by us. We have operated the
Montana portfolio only since December 17, 1999. We cannot assure you that we
will be successful in operating the Montana portfolio in a competitive
environment in which energy rates will be set by market forces.
SIGNIFICANT UNEXPECTED CAPITAL EXPENDITURES COULD DECREASE OUR CASH FLOW AND
OPERATING INCOME.
We expect to make continued capital expenditures for the Montana portfolio.
Equipment replacement or modification expenditures and costs of compliance with
environmental standards will continue to be reflected in our capital
expenditures and operating costs. We intend to fund these capital expenditures
and the aggregate rent payments under the leases primarily from cash flow from
our operations. Significant unexpected capital expenditures could decrease our
cash flow and operating income and impair our ability to pay our lease
obligation.
WE MUST SATISFY SUBSTANTIAL ENERGY REGULATORY REQUIREMENTS, WHICH COULD INCREASE
OUR COSTS OF COMPLIANCE AND LIMIT OUR OPERATIONS.
Statutory or regulatory changes or judicial or administrative
interpretations of existing energy regulatory laws, regulations or licenses that
impose more comprehensive or stringent requirements on us could affect our
business in the following ways.
Energy regulatory matters
We believe that we have obtained all material energy-related approvals
required to operate the Montana portfolio, and that the owner lessors have
obtained all energy-related approvals required for them to enter into the lease
transactions. We may be required to obtain additional regulatory approvals,
including, without limitation, licenses, renewals, extensions, transfers,
assignments, reissuances or similar actions. We cannot assure you that we will
be able to:
- obtain all required regulatory approvals that we may require in the
future;
- obtain any necessary modifications to existing regulatory approvals; or
- maintain compliance with all applicable energy regulatory laws,
regulations, ordinances and approvals.
Delay in obtaining or failure to obtain and maintain in full force and
effect any required regulatory approvals, or delay or failure to satisfy any
applicable regulatory requirements, could prevent operation of, or the sale of
energy from, the assets included in the Montana portfolio, or could result in
potential civil or criminal liability or in additional costs to us.
Hydroelectric licensing issues
The hydroelectric generating facilities collectively are covered by four
Federal Energy Regulatory Commission project licenses issued under Part I of the
Federal Power Act. The licenses expire in 2009, 2025,
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2035 and 2040, respectively. Although the terms and conditions of each
respective license are applicable throughout the term of the license, some of
the licenses contain reopener provisions that during the existing license term
would permit the Federal Energy Regulatory Commission to establish new operating
parameters or environmental protection measures that could increase the cost of
operating the affected project in ways or to an extent that cannot be predicted
at this time. We cannot assure you that the terms and conditions of any new
licenses will be as favorable to us as the original licenses.
The Federal Energy Regulatory Commission's statutory authority to issue new
licenses to existing hydroelectric generating facilities that were previously
licensed requires the Federal Energy Regulatory Commission to consider and
include license conditions that "protect, mitigate damages to, and enhance fish
and wildlife . . . affected by the development, operation and management of the
project." Such conditions could take the form of, among other things,
operational protocols or construction of additional facilities, such as fish
passages, which could increase the cost to us of operating and maintaining the
hydroelectric generating facilities. Moreover, to the extent that a project is
located on lands under the protection of the federal government, the agencies
responsible for administering the government's interests are authorized to
formulate license conditions that the Federal Energy Regulatory Commission is
required by law to incorporate into the license. Such conditions could be
expected to increase the cost of operation or diminish the energy output of the
project.
ENVIRONMENTAL LAWS WILL AFFECT OUR BUSINESS PLANS AND COULD CAUSE COST INCREASES
BECAUSE WE HAVE ASSUMED LIABILITY FOR PRE-EXISTING ENVIRONMENTAL CONDITIONS AT
THE SITES OF THE GENERATING FACILITIES INCLUDED IN THE MONTANA PORTFOLIO.
Environmental regulatory approvals
We believe that we have obtained all material environmental-related
approvals required to operate the Montana portfolio or that these approvals have
been applied for and will be issued in a timely manner. The approvals concern,
among other things, the protection of the environment and the health and safety
of employees and the public. Failure to comply with the approvals and applicable
laws, regulations and ordinances could result in potential civil or criminal
liability, imposition of clean-up liens and fines and expenditures of funds to
bring the Montana portfolio into compliance. We cannot assure you that we will
be able to:
- obtain all environmental approvals that we may require in the future;
- obtain any necessary modifications to existing environmental approvals;
or
- maintain compliance with all applicable environmental laws, regulations,
ordinances and approvals.
Delay in obtaining or failure to obtain and maintain in full force and
effect any required environmental approvals, or delay or failure to satisfy any
applicable environmental regulatory requirements, could prevent operation of, or
the sale of energy from, assets included in the Montana portfolio, or could
result in potential civil or criminal liability or in additional costs to us.
Responsibility for environmental liabilities
Under the asset purchase agreement for our acquisition of the Montana
portfolio, we assumed responsibility for losses resulting from or arising out of
pre-existing environmental conditions or violations of environmental laws
relating to the Montana portfolio. However, MPC has retained liability related
to its hazardous materials which either are transported off-site or released
off-site. MPC has agreed to indemnify us for losses relating to pre-existing
on-site environmental conditions, including any fines or penalties imposed upon
us by a governmental authority relating to MPC's ownership, operation and
maintenance of the Montana portfolio. MPC has also agreed to indemnify us if the
Montana Department of Environmental Quality requires us to remediate metals at
the Thomspon Falls facility or changes the regulatory status of the Thompson
Falls facility.
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These indemnity obligations are limited and are not transferred to the
owner lessor. Also, MPC's obligation to indemnify us for losses associated with
the cost of remediating pre-existing on-site environmental conditions is limited
to 50% of its pro-rata share of such environmental liability not to exceed in
the aggregate 10% of the purchase price of the Montana portfolio. Although we
have performed our own environmental due diligence, we have not performed
on-site testing. Instead, we have relied on the environmental evaluations of the
Montana portfolio provided to us by MPC and an independent consulting firm in
connection with the acquisition. These environmental evaluations were performed
more than two years ago. Although we are not aware of any additional concerns,
we cannot assure you that these investigations uncovered all relevant site
conditions.
MPC's consultant has identified several areas in its report where
additional investigations and groundwater capture systems will be required to
maintain compliance with its certificate of environmental compatibility and
public need. We cannot assure you that other environmental occurrences or
conditions will not arise or be discovered in the future. These additional
occurrences and conditions could involve significant expense and we may be
unable to seek indemnification from MPC for the resulting costs.
In 1999, the Environmental Protection Agency initiated enforcement actions
against operators of older, coal-fired generating facilities, asserting that
those facilities have, over the years, been modified in ways that subject them
to more stringent "New Source" requirements under the Clean Air Act. The
Environmental Protection Agency has issued an information request to us related
to the Corette facility. Compliance with any such Environmental Protection
Agency enforcement action could result in additional capital and operating
expenses in amounts which are not determinable at this time, but which could be
significant.
WE MAY HAVE TO PAY INCREASED TRANSMISSION COSTS OR FACE CONSTRAINTS IN OUR
ABILITY TO TRANSMIT ENERGY.
While we deliver most of the energy we generate to customers in Montana,
approximately 20% of the energy that we generate is expected to be delivered to
customers outside Montana via the Colstrip transmission system or other
transmission paths. We or our customers will reserve transmission service on the
Colstrip transmission system or on other transmission paths under Federal Energy
Regulatory Commission mandated open-access tariffs or Bonneville Power
Administration tariffs.
Significant regional transmission developments. The Bonneville Power
Administration's transmission system is a primary outlet to the Northwest for
exported energy from Montana. The Bonneville Power Administration is a federal
entity that owns more than half of the transmission facilities in the Northwest
and also supplies about 40% of the region's energy. While the Bonneville Power
Administration has indicated an intention to voluntarily comply with the Federal
Energy Regulatory Commission's policies concerning open transmission access, it
is not required to do so under current law. The Bonneville Power Administration
also sets its own transmission rates through an administrative process in which
its customers can participate. Bonneville Power Administration rate proceedings
are currently underway which could increase the Bonneville Power
Administration's transmission rates. We believe the Bonneville Power
Administration's transmission rates are and are likely to remain reasonable.
However, in view of the remoteness of our generating facilities from some of our
target markets, and the Bonneville Power Administration's dominance of regional
transmission, the future policies, practices and structure of the Bonneville
Power Administration (and any successor entities) could affect the marketing of
our energy to the Northwest by increasing the price we must pay for
transmission, limiting our access to its transmission system or in other ways.
The formation of a regional transmission organization, or RTO, in the
Northwest could also affect the transmission of the energy we generate. On
October 23, 2000, nine transmission owning utilities in the Northwest Power Pool
region and southern Nevada made a supplemental compliance filing with the
Federal Energy Regulatory Commission for the proposed formation of a non-profit
RTO independent system operator, to be called RTO West. While we cannot be
certain what form RTO West may eventually take, the currently contemplated
proposal calls for RTO West to operate the transmission facilities of all the
filing transmission owners that intend to file the proposal including the
Bonneville Power Administration and the current owners of the Colstrip
transmission system. While we expect that RTO West would enhance transmission
reliability
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and reduce some transmission fees, we cannot be certain what effect it will
ultimately have on transmission in the Northwest and the rest of the Western
Systems Coordinating Council.
Purchase of the Colstrip transmission system. Under our asset purchase
agreement with MPC, we have agreed to purchase from MPC the portion of the
Colstrip transmission system that is related to the interests in the Colstrip
facility that we acquired from MPC. Negotiations to complete this acquisition
are ongoing. However, we cannot assure you that we will acquire all or any
portion of these interests in the Colstrip transmission system or that the
acquisition will occur within any given period of time. If we do not acquire, or
if we are significantly delayed in acquiring, that portion of the Colstrip
transmission system from MPC, it may increase our costs of transmitting energy.
Open-Access tariffs. Any person can reserve access on the Colstrip
transmission system if available under open-access tariffs regardless of whether
it has an interest in the Colstrip transmission system or the Colstrip facility.
This could result in transmission constraints to us or to other users of the
Colstrip transmission system (including our customers). This may also result in
the need for us or other users of the Colstrip transmission system to upgrade
the Colstrip transmission system or to bear some portion of the cost associated
with upgrading the Colstrip transmission system. We cannot assure you that this
situation will not arise in the future.
In addition, under the Federal Power Act, transmission owners (including
us, if we acquire an interest in the Colstrip transmission system) are able to
modify existing tariffs or file new tariffs from time to time. Thus, we cannot
assure you that the terms and conditions of these third party open-access
tariffs will not change in the future. The Federal Power Act provides procedural
rights to transmission customers in the event of disputes over tariffs and
open-access, but we cannot assure you that any dispute would be resolved
favorably.
THE ENERGY CRISIS IN CALIFORNIA MAY EXPOSE US TO LITIGATION AND AFFECT OUR
FUTURE PROFITS.
Starting in mid-December 2000 the U.S. Secretary of Energy ordered a number
of wholesale power sellers in the western United States, including us, to sell
to the California Independent System Operator all amounts of energy that such
sellers had available in excess of their existing firm power commitments. From
mid-December through the expiration of the most recent order on February 7,
2001, we delivered approximately 1,700 MWh to the California Independent System
Operator pursuant to these orders. In addition, in December 2000 we made
voluntary sales of energy to the California Independent System Operator prior to
the date the first order was issued. As of December 31, 2000 we have fully
reserved for possible underrecoveries of payments for these energy sales. We may
have to add to our reserves in future periods if we are required by the U.S.
Secretary of Energy or other authority to continue to supply the California
Independent System Operator.
Litigation arising out of the California supply situation has been filed at
the Federal Energy Regulatory Commission and in California courts against
sellers of energy to the California Independent System Operator. The plaintiffs
and intervenors allege abuse of market power, among other things, and seek price
caps on wholesale sales in California and other Western power markets, refunds
of excess profits allegedly earned on these sales, and other relief, including
treble damages and attorneys' fees. We have intervened in the Federal Energy
Regulatory Commission proceedings in order to protect our interests, but have
not been named as a defendant in any of the court actions. We cannot predict
whether we will eventually be named in these lawsuits or other lawsuits and
cannot predict the outcome of any such litigation.
If the eventual resolution of the California power supply crisis involves
the imposition of price caps or other regulatory controls on wholesale energy
sales, our future cash flow and financial condition could be adversely affected.
Our business plan assumes we will sell at least a portion of the energy we
produce at wholesale market prices. If regulatory price controls are imposed on
us, our revenues may be reduced.
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IT IS POSSIBLE THAT THE LEASES COULD BE TERMINATED, OR THAT WE COULD ASSIGN THE
LEASES TO A NEW OBLIGOR, IF WE BECOME A DEBTOR IN A BANKRUPTCY PROCEEDING.
The certificates are not our direct obligations. If we were to become a
debtor in a liquidation or reorganization case under the United States
bankruptcy code, we, or our bankruptcy trustee, could reject the leases as
"executory" contracts under Section 365 of the bankruptcy code. If that happens,
rent payments under the leases would terminate, leaving the owner lessors
without regular rent payments and with a claim for damages for breach of the
leases. While the owner lessors could then file claims for damages, the amount
of any recovery on those claims and the amount of time that would pass between
the commencement of the bankruptcy case and the receipt of any recovery cannot
be determined. If we were to become a debtor in a case under the bankruptcy
code, an event of default under the indenture would occur.
Under Montana law, it is possible that the leases will be viewed as leases
of real, rather than personal, property. If the leases are rejected in a
bankruptcy proceeding, Section 502(b)(6) of the bankruptcy code limits the
claims of lessors under unexpired leases of real property. If a bankruptcy court
concluded that the leases are leases of real property, damages for the rejection
of a lease would be limited to the greater of one year's rent under the lease or
15% of the remaining rent under the lease (not to exceed three years' rent).
These damages might not be sufficient to cover debt service on the lessor notes
and, accordingly, the certificates.
The leases would not be subject to the risks of the foregoing
characterizations if a court determined that they constitute "financing leases"
within the meaning of the bankruptcy code. "Financing leases" are leases
intended as security and are in substance installment sales or loans. The issue
of whether leases such as ours could be characterized as financing leases has
not yet been definitively addressed by the courts. Resolution of this issue
would depend on a bankruptcy court's analysis of the particular facts and
circumstances associated with the lease transactions. Therefore, we cannot
predict with any degree of certainty whether a court would conclude that the
leases constitute "financing leases" for purposes of the bankruptcy code.
It is also possible that we could, in a bankruptcy proceeding, elect to
cure defaults under the leases and to assume and assign the leases, in which
event the ultimate source of payments under the leases (and thus on the
certificates) would be an entity other than us. While the assignee would have to
demonstrate its ability to perform under the assumed leases, we cannot assure
you that the assignee could satisfy our obligations under the leases.
IT MAY BE DIFFICULT TO REALIZE THE VALUE OF THE COLLATERAL PLEDGED TO SECURE THE
LESSOR NOTES AND THE CERTIFICATES.
Each lessor note is secured by collateral which includes, subject to
customary exceptions, the rights and interests of the owner lessor issuing the
lessor note in the related leased assets, participation agreement, lease, site
lease and sublease. If a default occurs with respect to one or more of the
lessor notes, we cannot assure you that an exercise of remedies, including
foreclosure on the related collateral, would provide sufficient funds to repay
all amounts due on the defaulted lessor notes and, consequently, the
certificates.
The leases and the other lease documents do not contain
cross-collateralization or general cross-default provisions. In other words,
each indenture trustee's security interests in the collateral for the related
lessor note are separate from the security interests of the other indenture
trustees and do not secure the other lessor notes. In addition, a default under
a lease would not necessarily result in a default under the other leases. If an
indenture trustee exercises its right to foreclose on and sell its collateral,
the proceeds from the sale would be applied only to repay the lessor note
secured by that collateral. The proceeds could not be used to satisfy any
deficiency in the proceeds from the sale of collateral securing the other lessor
notes, and by operation of law any excess proceeds would be remitted to the
applicable owner lessor. As a result, the amount of proceeds from the sale of
collateral related to a lessor note might not be sufficient to pay all
principal, premium, if any, and interest due on the lessor note even though the
aggregate sale proceeds from all of the collateral would have been sufficient
for such purpose.
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Several other factors may affect the value of the collateral in a
foreclosure, including:
Limitations on transferability of required governmental approvals. If an
indenture trustee exercises its right to foreclose on the collateral related to
a particular portion of the leased assets, the purchaser or new operator of the
generating facilities may have difficulty obtaining in a timely manner all
governmental approvals required to operate the generating facilities.
Effect of Colstrip facility ownership and operating agreements. The
Colstrip units 1 and 2 ownership and operating agreements and the Colstrip units
3 and 4 ownership and operating agreement provide the owners of the Colstrip
facility with rights of first refusal for transfers of ownership interests in
Colstrip units 1 and 2 and Colstrip units 3 and 4, respectively. In addition, no
transfer of an interest in the Colstrip units may be made unless the
transferor's rights under the other agreements relating to the Colstrip units
are simultaneously transferred to the proposed transferee. If an indenture
trustee were to attempt to foreclose on the leased assets, it would be bound by
these limitations, which could affect the ability of the indenture trustee to
complete the foreclosure or the prices at which the leased assets could be sold.
Any transferee would also be subject to the other provisions of the Colstrip
ownership and operating agreements, which are discussed in a risk factor below.
Limitations on access to the Colstrip transmission system. The Colstrip
transmission system is not part of the leased assets. If an event of default
under a lease and subsequent foreclosure occurs, the applicable indenture
trustee or any transferee of the leased assets would most likely be required to
obtain transmission service from us, under our open-access tariff (in the event
we own a portion of the Colstrip transmission system) or from the other owners
of the Colstrip transmission system under their open-access tariffs. The cost to
any new owner for transmission service under these circumstances could affect
the value of the leased assets in a foreclosure.
Limitations on indemnity. Our asset purchase agreement with MPC requires
that MPC indemnify us for certain breaches of its representations, warranties or
covenants and for certain losses related to pre-existing on-site environmental
conditions. This indemnification right runs only to us and we will not assign
our right to be indemnified by MPC to the owner lessors, including with respect
to the Colstrip facility. Accordingly, such indemnification rights do not form
part of the collateral.
BECAUSE WE ONLY HOLD A 50% LEASEHOLD INTEREST IN COLSTRIP UNITS 1 AND 2 AND A
MINORITY POSITION IN COLSTRIP UNITS 3 AND 4, WE MAY NOT BE ABLE TO TAKE
IMPORTANT ACTIONS WITHOUT THE CONSENT OF THE OTHER COLSTRIP OWNERS.
We act as the operator of the Colstrip facility, which under the Colstrip
ownership and operating agreements gives us special rights to propose or concur
in a variety of actions which could affect operations at the Colstrip facility.
However, some actions require the approval of other participants in the Colstrip
facility. The priorities and incentives of the other Colstrip owners with
respect to the Colstrip facility may not be the same as ours.
We control only 50% of the votes related to Colstrip units 1 and 2, while
Puget controls the other 50% of the votes. Puget must approve the annual budget
that we propose for Colstrip units 1 and 2, although it cannot unreasonably
withhold its approval. If Puget does not agree with expenditures that we want to
make, it could be more difficult for us to make necessary or desirable
improvements to Colstrip units 1 and 2.
The agreements governing Colstrip units 3 and 4 set out many activities
that require the approval of the owners of these units. We hold an effective 15%
vote related to Colstrip units 3 and 4 (subject to a vote sharing agreement
between us and MPC). Accordingly, we do not control enough votes to
affirmatively satisfy the 55%, 65%, 85% or unanimous voting thresholds described
in this prospectus with respect to actions affecting Colstrip units 3 and 4. As
a result, the consent of the Colstrip owners other than ourselves would be
required for many important decisions affecting the Colstrip facility, including
decisions concerning certain capital expenditures.
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We did not purchase MPC's 30% leasehold interest in Colstrip unit 4. We
have entered into a vote sharing agreement with MPC, which gives MPC certain
rights which could limit our ability to vote as we wish in regard to matters
affecting Colstrip unit 3. If there is a default under the MPC Colstrip unit 4
lease, the Colstrip unit 4 lessors could gain control of our vote under the vote
sharing agreement. In addition, under certain circumstances, MPC may transfer
its interest in Colstrip unit 4. This vote sharing agreement would be binding on
any assignee of MPC's Colstrip unit 4 leasehold interest.
WE COULD BE EXPOSED TO CLAIMS BY THE OTHER OWNERS OF THE COLSTRIP FACILITY IF WE
FAIL TO OPERATE THE COLSTRIP FACILITY IN A PRUDENT MANNER.
As the operator of the Colstrip facility, we exercise broad authority over
day-to-day operations. We have agreed with the other owners of the Colstrip
facility to exercise our operator responsibilities in accordance with prevailing
standards of prudent utility practice, guidelines established by the Colstrip
owners' committees and applicable laws and regulations. As is typically the case
with joint ownership arrangements for generating facilities in the electric
utility industry, these standards are general in nature and can be subject to
differing interpretations. We could be exposed to claims by the other owners
arising out of our operation of the Colstrip facility if we interpret these
standards of conduct differently than the other owners do, or if we fail to
comply with the provisions of the Colstrip ownership and operating agreements
governing the four Colstrip units.
WE MAY NOT BE ABLE TO RELY ON PPL CORPORATION FOR FUTURE EQUITY FUNDING THAT WE
MAY NEED; ADDITIONALLY, PPL CORPORATION CONTROLS US AND ITS INTERESTS MAY COME
INTO CONFLICT WITH YOURS.
We are an indirect wholly owned subsidiary of PPL Corporation. Since our
formation, PPL Corporation has indirectly provided all of our equity funding.
Our only source of future funding in addition to permitted indebtedness under
the participation agreements, which includes indebtedness under the working
capital facility, is cash flow from the Montana portfolio. PPL Corporation is
not obligated to provide any loans or equity contributions to make up a
shortfall between the amount of our commitments and the foregoing sources of
funds other than its obligation to provide $97 million in equity to us for our
obligation under our asset purchase agreement with MPC to purchase a portion of
the Colstrip transmission system.
PPL Corporation has the power to control us. In circumstances involving a
conflict of interest between PPL Corporation as our sole indirect equity owner,
on the one hand, and the certificate holders as our indirect creditors, on the
other hand, we cannot assure you that PPL Corporation would not exercise its
power to control us in a manner that would benefit PPL Corporation to the
detriment of the certificate holders.
PPL Corporation's existing generating facilities do not currently compete
with the Montana portfolio. However, it is possible that in the future PPL
Corporation or its subsidiaries may undertake projects that could compete with
the Montana portfolio.
YOUR INVESTMENT MAY BE NOT BE LIQUID, BECAUSE THERE IS NO EXISTING MARKET FOR
THE CERTIFICATES AND AN ACTIVE TRADING MARKET MAY NEVER DEVELOP.
The certificates have not been and, until completion of the exchange offer
described in this prospectus, will not be registered under the Securities Act
and will be subject to transfer restrictions. There is no existing market for
the certificates and we do not intend to apply for listing of the certificates
on any securities exchange. There can be no assurance as to the liquidity of any
market that may develop for the certificates, the ability of the certificate
holders to sell their certificates or the price at which the certificate holders
will be able to sell their certificates. Future trading prices for the
certificates will depend on many factors, including, among other things,
prevailing interest rates, our operating results and the market for similar
securities.
Chase Securities Inc., Credit Suisse First Boston Corporation, UBS Warburg
LLC and TD Securities (USA) Inc., which we refer to as the initial purchasers,
have informed us that they intend to make a market in the certificates. However,
the initial purchasers are not obligated to do so and can terminate their
market-making activities at any time without notice. If a market for the
certificates does not develop, purchasers may be unable to resell the
certificates for an extended period of time. Consequently, a certificate holder
may not be able to liquidate its investment in a timely manner, and the
certificates may not be readily accepted as
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collateral for loans. In addition, any activity will be subject to restrictions
imposed by the Securities Act and the Securities Exchange Act of 1934, which we
refer to as the Exchange Act.
We will be required to file periodic reports under the Exchange Act only so
long as required by law. Under current Exchange Act rules, if there are fewer
than 300 certificate holders we would be required to file reports for only one
year after the registration statement is declared effective. If we are not
otherwise required to file Exchange Act reports after the one year period, any
filing of reports with the SEC would be at our discretion. A decision not to
file reports would result in a lack of publicly available information about us
and the certificates and may affect the liquidity and marketability of the
certificates.
THIS PROSPECTUS CONTAINS FORWARD-LOOKING STATEMENTS THAT ARE DEPENDENT ON EVENTS
AND CIRCUMSTANCES THAT ARE OUTSIDE OF OUR CONTROL.
This prospectus includes forward-looking statements, which give our current
expectations of future events. You will recognize these statements because they
do not strictly relate to historical or current facts. The forward-looking
statements may use words such as "anticipate," "estimate," "expect," "project,"
"intend," "think," "believe," "will," "should" and other words or terms of
similar meaning in connection with any discussion of our future performance. For
example, the forward-looking statements relate to our future actions,
performance and expenses, and to the impact of the capital markets on our
liquidity. We have based these forward-looking statements on our current
expectations based upon our knowledge of facts as of the date of this prospectus
and our assumptions about future events.
Any or all of the forward-looking statements in this prospectus and in any
other public statements we make may turn out to be incorrect. They can be
affected by inaccurate assumptions or by known or unknown risks and
uncertainties. Many factors, which cannot be predicted with certainty, will be
important in determining our future results. Among these factors are:
- the application of governmental, statutory, regulatory or administrative
laws, rules and regulations to us, our subsidiaries, the Montana
portfolio and the United States energy industry generally;
- demand for and pricing of the electric capacity and energy in the markets
served by our generating facilities;
- the future nature of the markets where we plan to sell energy;
- competition from other generating facilities, including new facilities
that may be developed in the future;
- the cost and availability of fuel and fuel transportation services for
our generating facilities;
- the performance of our generating facilities;
- our limited operating history;
- the cost and availability of transmission capacity for the energy
generated by our generating facilities or required to satisfy energy
sales made on our behalf.
As a result of these factors, our actual future results may vary materially
from those described in the forward-looking statements. Except to the extent of
our obligations under the federal securities laws to disclose material
information, we are under no obligation to update the forward-looking statements
contained in this prospectus.
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THIS EXCHANGE OFFER
PURPOSE AND TERMS OF THIS EXCHANGE OFFER
The old certificates were originally sold on July 20, 2000 in an offering
that was exempt from the registration requirements of the Securities Act. As of
the date of this prospectus, $338 million aggregate principal amount of old
certificates are outstanding. In connection with the sale of the old
certificates, we entered into a registration rights agreement in which we agreed
to file with the SEC a registration statement with respect to the exchange of
old certificates for new certificates and to use our best efforts to cause the
registration statement to become effective by March 17, 2001 and to complete the
exchange offer on or prior to April 16, 2001. Under the registration rights
agreement, we also agreed to pay additional interest at a rate of 0.50% per
annum on the old certificates if we failed to meet either of these deadlines.
The additional interest would be payable on the old certificates on the regular
interest payment dates. We filed a copy of the registration rights agreement as
an exhibit to the registration statement of which this prospectus is a part.
This exchange offer satisfies our contractual obligations under the registration
rights agreement.
We are offering, upon the terms and subject to the conditions set forth in
this prospectus and in the accompanying letter of transmittal, to exchange up to
$338 million aggregate principal amount of old certificates for $338 million
aggregate principal amount of new certificates which have been registered under
the Securities Act. We will accept for exchange old certificates that you
properly tender prior to the expiration date and do not withdraw in accordance
with the procedures described below. You may tender your old certificates in
whole or in part in integral multiples of $1,000 principal amount.
This exchange offer is not conditioned upon the tender for exchange of any
minimum aggregate principal amount of old certificates. We reserve the right in
our sole discretion to purchase or make offers for any old certificates that
remain outstanding after the expiration date or, as detailed under the caption
"-- Conditions to this exchange offer," to terminate this exchange offer and, to
the extent permitted by applicable law, purchase old certificates in the open
market, in privately negotiated transactions or otherwise. The terms of any of
these purchases or offers could differ from the terms of this exchange offer.
There will be no fixed record date for determining the registered holders of the
old certificates entitled to participate in the exchange offer.
Only a registered holder of the old certificates (or the holder's legal
representative or attorney-in-fact) may participate in the exchange offer.
Holders of old certificates do not have any appraisal or dissenters' rights in
connection with this exchange offer. Old certificates which are not tendered in,
or are tendered but not accepted in connection with, this exchange offer will
remain outstanding. We intend to conduct this exchange offer in accordance with
the provisions of the registration rights agreement and the applicable
requirements of the Securities Act and SEC rules and regulations.
If we do not accept any old certificates that you tender for exchange
because of an invalid tender, the occurrence of other events set forth in this
prospectus or otherwise, we will return the certificates for any unaccepted old
certificates to you, without expense, after the expiration date.
If you tender old certificates in connection with this exchange offer, you
will not be required to pay brokerage commissions or fees or, subject to the
instructions in the letter of transmittal, transfer taxes with respect to the
exchange of old certificates in connection with this exchange offer. We will pay
all charges and expenses, other than certain applicable taxes described below,
in connection with this exchange offer. See "-- Fees and expenses."
Unless the context requires otherwise, the term "holder" with respect to
this exchange offer means any person in whose name the old certificates are
registered on the pass through trustee's books or any other person who has
obtained a properly completed bond power from the registered holder, or any
participant in DTC whose name appears on a security position listing as a holder
of old certificates.
For purposes of this exchange offer, a participant includes beneficial
interests in the old certificates held by direct or indirect participants and
old certificates held in definitive form.
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WE MAKE NO RECOMMENDATION TO YOU AS TO WHETHER YOU SHOULD TENDER OR REFRAIN
FROM TENDERING ALL OR ANY PORTION OF YOUR OLD CERTIFICATES INTO THIS EXCHANGE
OFFER. IN ADDITION, NO ONE HAS BEEN AUTHORIZED TO MAKE THIS RECOMMENDATION. YOU
MUST MAKE YOUR OWN DECISION WHETHER TO TENDER INTO THIS EXCHANGE OFFER AND, IF
SO, THE AGGREGATE AMOUNT OF OLD CERTIFICATES TO TENDER AFTER READING THIS
PROSPECTUS AND THE LETTER OF TRANSMITTAL AND CONSULTING WITH YOUR ADVISORS, IF
ANY, BASED ON YOUR FINANCIAL POSITION AND REQUIREMENTS.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The term "expiration date" means 5:00 p.m., New York City time, on
[ ], 2001 unless we extend this exchange offer, in which case the term
"expiration date" shall mean the latest date and time to which we extend this
exchange offer and the consent solicitation.
We expressly reserve the right, at any time or from time to time, so long
as applicable law allows,
(1) to delay our acceptance of old certificates for exchange;
(2) to terminate or amend this exchange offer if, in the opinion of
our counsel, completing the exchange offer would violate any applicable
law, rule or regulation or any SEC staff interpretation; and
(3) to extend the expiration date and retain all old certificates
tendered into this exchange offer, subject, however, to your right to
withdraw your tendered old certificates as described under "-- Withdrawal
rights."
If this exchange offer is amended in a manner that we think constitutes a
material change, or if we waive a material condition of this exchange offer, we
will promptly disclose the amendment by means of a prospectus supplement that
will be distributed to the registered holders of the old certificates, and we
will extend this exchange offer to the extent required by Rule 14e-1 under the
Exchange Act.
We will promptly follow any delay in acceptance, termination, extension or
amendment by oral or written notice of the event to the exchange agent followed
promptly by oral or written notice to the registered holders. Should we choose
to delay, extend, amend or terminate the exchange offer, we will have no
obligation to publish, advertise or otherwise communicate this announcement,
other than by making a timely release to an appropriate news agency.
PROCEDURES FOR TENDERING THE OLD CERTIFICATES
Upon the terms and the conditions of this exchange offer, we will exchange,
and we will arrange for the pass through trusts to issue to the exchange agent,
new certificates for old certificates that have been validly tendered and not
validly withdrawn promptly after the expiration date. The tender by a holder of
any old certificates and our acceptance of that holder's old certificates will
constitute a binding agreement between us and that holder subject to the terms
and conditions set forth in this prospectus and the accompanying letter of
transmittal.
Valid tender
We will deliver new certificates in exchange for old certificates that have
been validly tendered and accepted for exchange pursuant to this exchange offer.
Except as set forth below, you will have validly tendered your old certificates
pursuant to this exchange offer if the exchange agent receives prior to the
expiration date at the address listed under the caption "-- Exchange agent:"
(1) a properly completed and duly executed letter of transmittal, with
any required signature guarantees, including all documents required by the
letter of transmittal; or
(2) if the old certificates are tendered in accordance with the
book-entry procedures set forth below, the tendering old certificate holder
may transmit an agent's message (described below) instead of a letter of
transmittal.
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In addition, on or prior to the expiration date:
(1) the exchange agent must receive the old certificates along with
the letter of transmittal; or
(2) the exchange agent must receive a timely book-entry confirmation
of a book-entry transfer of the tendered old certificates into the exchange
agent's account at DTC according to the procedure for book-entry transfer
described below, along with a letter of transmittal or an agent's message
in lieu of the letter of transmittal; or
(3) the holder must comply with the guaranteed delivery procedures
described below.
Accordingly, we may not make delivery of new certificates to all tendering
holders at the same time since the time of delivery will depend upon when the
exchange agent receives the old certificates, book-entry confirmations with
respect to old certificates and the other required documents.
The term "book-entry confirmation" means a timely confirmation of a
book-entry transfer of existing pass through trust certificates into the
exchange agent's account at DTC. The term "agent's message" means a message,
transmitted by DTC to and received by the exchange agent and forming a part of a
book-entry confirmation, which states that DTC has received an express
acknowledgment from the tendering participant stating that the participant has
received and agrees to be bound by the letter of transmittal and that we may
enforce the letter of transmittal against the participant.
If you tender less than all of your old certificates, you should fill in
the amount of old certificates you are tendering in the appropriate box on the
letter of transmittal or, in the case of a book-entry transfer, so indicate in
an agent's message if you have not delivered a letter of transmittal. The entire
amount of old certificates delivered to the exchange agent will be deemed to
have been tendered unless otherwise indicated.
If any letter of transmittal, endorsement, bond power, power of attorney,
or any other document required by the letter of transmittal is signed by a
trustee, executor, administrator, guardian, attorney-in-fact, officer of a
corporation or other person acting in a fiduciary or representative capacity,
that person should so indicate when signing, and, unless waived by us, you must
submit evidence satisfactory to us, in our sole discretion, of that person's
authority to so act.
If you are a beneficial owner of old certificates that are held by or
registered in the name of a broker, dealer, commercial bank, trust company or
other nominee or custodian, we urge you to contact this entity promptly if you
wish to participate in this exchange offer.
THE METHOD OF DELIVERY OF OLD CERTIFICATES, THE LETTER OF TRANSMITTAL AND
ALL OTHER REQUIRED DOCUMENTS IS AT YOUR OPTION AND AT YOUR SOLE RISK, AND
DELIVERY WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED BY THE EXCHANGE AGENT.
INSTEAD OF DELIVERY BY MAIL, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND
DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE
TIMELY DELIVERY AND YOU SHOULD OBTAIN PROPER INSURANCE. DO NOT SEND ANY LETTER
OF TRANSMITTAL OR OLD CERTIFICATES TO PPL MONTANA. YOU MAY REQUEST YOUR BROKER,
DEALER, COMMERCIAL BANK, TRUST COMPANY OR NOMINEE TO EFFECT THESE TRANSACTIONS
FOR YOU.
Book-entry transfer
Holders who are participants in DTC tendering by book-entry transfer must
execute the exchange through the Automated Tender Offer Program of DTC on or
prior to the expiration date. DTC will verify this acceptance and execute a
book-entry transfer of the tendered Certificates into the exchange agent's
account at DTC. DTC will then send to the exchange agent a book-entry
confirmation including an agent's message confirming that DTC has received an
express acknowledgment from the holder that the holder has received and agrees
to be bound by the letter of transmittal and that the exchange agent and we may
enforce the letter of transmittal against such holder. The book-entry
confirmation must be received by the exchange agent in order for the exchange to
be effective.
The exchange agent will make a request to establish an account with respect
to the old certificates at DTC for purposes of this exchange offer within two
business days after the date of this prospectus unless the exchange agent
already has established an account with DTC suitable for this exchange offer.
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Any financial institution that is a participant in DTC's book-entry
transfer facility system may make a book-entry delivery of the existing pass
through trust certificates by causing DTC to transfer these existing pass
through trust certificates into the exchange agent's account at DTC in
accordance with DTC's procedures for transfers.
If the tender is not made through the Automated Tender Offer Program, you
must deliver the old certificates and the applicable letter of transmittal, or a
facsimile of the letter of transmittal, properly completed and duly executed,
with any required signature guarantees, or an agent's message in lieu of a
letter of transmittal, and any other required documents to the exchange agent at
its address listed under the caption "--Exchange agent" prior to the expiration
date, or you must comply with the guaranteed delivery procedures set forth below
in order for the tender to be effective.
Delivery of documents to DTC does not constitute delivery to the exchange
agent and book-entry transfer to DTC in accordance with its procedures does not
constitute delivery of the book-entry confirmation to the exchange agent.
Signature guarantees
Signature guarantees on a letter of transmittal or a notice of withdrawal,
as the case may be, are only required if:
(1) a certificate for old certificates is registered in a name other
than that of the person surrendering the certificate; or
(2) a registered holder completes the box entitled "Special Issuance
Instructions" or "Special Delivery Instructions" in the letter of
transmittal. See "Instructions" in the letter of transmittal.
In the case of (1) or (2) above, you must duly endorse these certificates
for old certificates or they must be accompanied by a properly executed bond
power, with the endorsement or signature on the bond power and on the letter of
transmittal or the notice of withdrawal, as the case may be, guaranteed by a
firm or other entity identified in Rule 17Ad-15 under the Exchange Act as an
"eligible guarantor institution" that is a member of a medallion guarantee
program, unless these pass through trust certificates are surrendered on behalf
of that eligible guarantor institution. An "eligible guarantor institution"
includes the following:
- a bank;
- a broker, dealer, municipal securities broker or dealer or government
securities broker or dealer;
- a credit union;
- a national securities exchange, registered securities association or
clearing agency; or
- a savings association.
Guaranteed delivery
If you desire to tender old certificates into this exchange offer and:
(1) the certificates for the old certificates are not immediately
available;
(2) time will not permit delivery of the old certificates and all
required documents to the exchange agent on or prior to the expiration
date; or
(3) the procedures for book-entry transfer cannot be completed on a
timely basis;
you may nevertheless tender the existing pass through trust certificates,
provided that you comply with all of the following guaranteed delivery
procedures:
(1) tender is made by or through an eligible guarantor institution;
(2) prior to the expiration date, the exchange agent receives from the
eligible guarantor institution a properly completed and duly executed
Notice of Guaranteed Delivery, substantially in the form
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accompanying the letter of transmittal. This eligible guarantor institution
may deliver the Notice of Guaranteed Delivery by hand or by facsimile or
deliver it by mail to the exchange agent and must include a guarantee by
this eligible guarantor institution in the form in the Notice of Guaranteed
Delivery; and
(3) within three New York Stock Exchange trading days after the date
of execution of the Notice of Guaranteed Delivery, the exchange agent must
receive:
(a) the certificates, or book-entry confirmation, representing all
tendered old certificates, in proper form for transfer;
(b) a properly completed and duly executed letter of transmittal or
facsimile of the letter of transmittal or, in the case of a book-entry
transfer, an agent's message in lieu of the letter of transmittal, with
any required signature guarantees; and
(c) any other documents required by the letter of transmittal.
Determination of Validity
- We have the right, in our sole discretion, to determine all questions as
to the form of documents, validity, eligibility, including time of
receipt, and acceptance for exchange of any tendered existing pass
through trust certificates. Our determination will be final and binding
on all parties.
- We reserve the absolute right, in our sole and absolute discretion, to
reject any and all tenders of old certificates that we determine are not
in proper form.
- We reserve the absolute right, in our sole and absolute discretion, to
refuse to accept for exchange a tender of old certificates if our counsel
advises us that the tender is unlawful.
- We also reserve the absolute right, so long as applicable law allows, to
waive any of the conditions of this exchange offer or any defect or
irregularity in any tender of old certificates of any particular holder
whether or not similar defects or irregularities are waived in the case
of other holders.
- Our interpretation of the terms and conditions of this exchange offer,
including the letter of transmittal and the instructions relating to it,
will be final and binding on all parties.
- We will not consider the tender of existing pass through trust
certificates to have been validly made until all defects or
irregularities with respect to the tender have been cured or waived.
- We, our affiliates, the exchange agent, and any other person will not be
under any duty to give any notification of any defects or irregularities
in tenders and will not incur any liability for failure to give this
notification.
ACCEPTANCE FOR EXCHANGE FOR THE NEW CERTIFICATES
Upon satisfaction or waiver of all of the conditions of this exchange
offer, we will accept, promptly after the expiration date, all old certificates
properly tendered and will arrange for the pass through trusts to issue the new
certificates promptly after acceptance of the old certificates. See
"-- Conditions to this exchange offer." Subject to the terms and conditions of
this exchange offer, we will be deemed to have accepted for exchange, and
exchanged, old certificates validly tendered and not withdrawn as, if and when
we give oral or written notice to the exchange agent, with any oral notice
promptly confirmed in writing by us, of our acceptance of these old certificates
for exchange in this exchange offer. The exchange agent will act as our agent
for the purpose of receiving tenders of existing pass through trust
certificates, letters of transmittal and related documents, and as agent for
tendering holders for the purpose of receiving old certificates, letters of
transmittal and related documents and transmitting new certificates to holders
who validly tendered old certificates. The exchange agent will make the exchange
promptly after the expiration date. If for any reason whatsoever:
- the acceptance for exchange or the exchange of any old certificates
tendered in this exchange offer is delayed, whether before or after our
acceptance for exchange of old certificates;
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- we extend this exchange offer; or
- we are unable to accept for exchange or exchange old certificates
tendered in this exchange offer;
then, without prejudice to our rights set forth in this prospectus, the
exchange agent may, nevertheless, on our behalf and subject to Rule 14e-1(c)
under the Exchange Act, retain tendered old certificates and these old
certificates may not be withdrawn unless tendering holders are entitled to
withdrawal rights as described under "-- Withdrawal rights."
INTEREST
For each old certificate that we accept for exchange, the old certificate
holder will receive a new certificate having a principal amount and final
distribution date equal to that of the surrendered old certificate. Interest on
the new certificates will accrue from July 20, 2000, the original issue date of
the old certificates or from any later interest distribution date preceding
completion of this exchange offer on which all scheduled interest was
distributed in respect of the old certificates tendered for exchange. January 2,
2001 was the first scheduled interest distribution date.
RESALES OF THE NEW CERTIFICATES
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new certificates may be
offered for resale, resold and otherwise transferred by you without compliance
with the registration and prospectus delivery requirements of the Securities Act
provided that:
- you acquire any new certificate in the ordinary course of your business;
- you are not participating, do not intend to participate, and have no
arrangement or understanding with any person to participate, in the
distribution of the new certificates;
- you are not a broker-dealer who purchased outstanding certificates
directly from us for resale pursuant to Rule 144A or any other available
exemption under the Securities Act; and
- you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new certificate without
delivering a prospectus meeting the requirements of the Securities Act or
without an exemption from registration of your certificates from these
requirements, you may incur liability under the Securities Act. We do not assume
any liability or indemnify you against any liability under the Securities Act.
Each broker-dealer that is issued new certificates for its own account in
exchange for certificates must acknowledge that it will deliver a prospectus
meeting the requirements of the Securities Act in connection with any resale of
the new certificates. A broker-dealer that acquired old certificates for its own
account as a result of market-making or other trading activities may use this
prospectus for an offer to resell, resale or other retransfer of the new
certificates.
WITHDRAWAL RIGHTS
Except as otherwise provided in this prospectus, you may withdraw your
tender of old certificates at any time prior to the expiration date. If you
withdraw your tender of old certificates, your consent to the proposed waiver
will also be deemed withdrawn. You may not withdraw your consent without
withdrawing your tender of old certificates.
- In order for a withdrawal to be effective, you must deliver a written,
telegraphic or facsimile transmission of a notice of withdrawal to the
exchange agent at any of its addresses listed under the caption
"-- Exchange agent" prior to the expiration date.
- Each notice of withdrawal must specify:
(1) the name of the person who tendered the old certificates to be
withdrawn;
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(2) the aggregate principal amount of old certificates to be
withdrawn; and
(3) if certificates for these old certificates have been tendered, the
name of the registered holder of the old certificates as set forth on the
old certificates, if different from that of the person who tendered these
old certificates.
- If you have delivered or otherwise identified to the exchange agent
certificates for old certificates, the notice of withdrawal must specify
the serial numbers on the particular certificates for the old
certificates to be withdrawn and the signature on the notice of
withdrawal must be guaranteed by an eligible guarantor institution,
except in the case of old certificates tendered for the account of an
eligible guarantor institution.
- If you have tendered old certificates in accordance with the procedures
for book-entry transfer listed in "-- Procedures for tendering the old
certificates -- Book-entry transfer," the notice of withdrawal must
specify the name and number of the account at DTC to be credited with the
withdrawal of existing pass through trust certificates and must otherwise
comply with the procedures of DTC.
- You may not rescind a withdrawal of your tender of old certificates.
- We will not consider old certificates properly withdrawn to be validly
tendered for purposes of this exchange offer. However, you may retender
old certificates at any subsequent time prior to the expiration date by
following any of the procedures described above in "-- Procedures for
tendering the old certificates."
- We, in our sole discretion, will determine all questions as to the
validity, form and eligibility, including time of receipt, of any
withdrawal notices. Our determination will be final and binding on all
parties. We, our affiliates, the exchange agent and any other person have
no duty to give any notification of any defects or irregularities in any
notice of withdrawal and will not incur any liability for failure to give
any such notification.
- We will return to the holder any old certificates which have been
tendered but which are withdrawn promptly after the withdrawal.
CONDITIONS TO THIS EXCHANGE OFFER
Notwithstanding any other provisions of this exchange offer or any
extension of this exchange offer, we will not be required to accept for
exchange, or to exchange, any old certificates. We may terminate this exchange
offer, whether or not we have previously accepted any old certificates for
exchange, or we may waive any conditions to or amend this exchange offer, if we
determine in our sole and absolute discretion that the exchange offer would
violate applicable law or any applicable interpretation of the staff of the SEC.
EXCHANGE AGENT
We have appointed The Chase Manhattan Bank as exchange agent for this
exchange offer. You should direct all deliveries of the letters of transmittal
and any other required documents, questions, requests for assistance and
requests for additional copies of this prospectus or of the letters of
transmittal to the exchange agent as follows:
By mail, overnight delivery or hand:
The Chase Manhattan Bank
55 Water Street, Room 234
New York, New York 10041
Attention: Victor Matis
By Facsimile:
212-638-7380
Confirm by telephone:
212-638-0459
DELIVERY TO OTHER THAN THE ABOVE ADDRESS OR FACSIMILE NUMBER WILL NOT
CONSTITUTE A VALID DELIVERY.
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FEES AND EXPENSES
We will bear the expenses of soliciting tenders of the old certificates. We
will make the initial solicitation by mail; however, we may decide to make
additional solicitations personally or by telephone or other means through our
officers, agents, directors or employees.
We have not retained any dealer-manager or similar agent in connection with
this exchange offer and we will not make any payments to brokers, dealers or
others soliciting acceptances of this exchange offer. We have agreed to pay the
exchange agent and pass through trustee reasonable and customary fees for its
services and will reimburse it for its reasonable out-of-pocket expenses in
connection with this exchange offer. We will also pay brokerage houses and other
custodians, nominees and fiduciaries the reasonable out-of-pocket expenses they
incur in forwarding copies of this prospectus and related documents to the
beneficial owners of old certificates, and in handling or tendering for their
customers.
TRANSFER TAXES
Holders who tender their old certificates will not be obligated to pay any
transfer taxes in connection with the exchange, except that if:
(1) you want us to deliver new certificates to any person other than
the registered holder of the old certificates tendered;
(2) you want the pass through trusts to issue the new certificates in
the name of any person other than the registered holder of the old
certificates tendered; or
(3) a transfer tax is imposed for any reason other than the exchange
of old certificates in connection with this exchange offer;
then you will be liable for the amount of any transfer tax, whether imposed on
the registered holder or any other person. If you do not submit satisfactory
evidence of payment of such transfer tax or exemption from such transfer tax
with the letter of transmittal, the amount of this transfer tax will be billed
directly to the tendering holder.
CONSEQUENCES OF EXCHANGING OR FAILING TO EXCHANGE OLD CERTIFICATES
Holders of old certificates who do not exchange their old certificates for
new certificates in this exchange offer will continue to be subject to the
provisions of the pass through trust agreement regarding transfer and exchange
of the old certificates and the restrictions on transfer of the old certificates
set forth on the legend on the old certificates. In general, the old
certificates may not be offered or sold, unless registered under the Securities
Act, except under an exemption from, or in a transaction not subject to, the
registration requirements of the Securities Act and applicable state securities
laws.
Based on interpretations by the staff of the SEC, as detailed in no-action
letters issued to third parties, we believe that new certificates issued in this
exchange offer in exchange for old certificates may be offered for resale,
resold or otherwise transferred by the holders (other than any holder that is an
"affiliate" of our company within the meaning of Rule 405 under the Securities
Act) without compliance with the registration and prospectus delivery provisions
of the Securities Act, provided that the new certificates are acquired in the
ordinary course of the holders' business and the holders have no arrangement or
understanding with any person to participate in the distribution of these new
certificates. However, we do not intend to request the SEC to consider, and the
SEC has not considered, the exchange offer in the context of a no-action letter
and we cannot guarantee that the staff of the SEC would make a similar
determination with respect to the exchange offer.
Each holder must acknowledge that it is not engaged in, and does not intend
to engage in, a distribution of new certificates and has no arrangement or
understanding to participate in a distribution of new certificates. If any
holder is an affiliate of our company, is engaged in or intends to engage in or
has any arrangement or
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understanding with respect to the distribution of the new certificates to be
acquired pursuant to the exchange offer, the holder:
- could not rely on the applicable interpretations of the staff of the SEC,
and
- must comply with the registration and prospectus delivery requirements of
the Securities Act.
Each broker-dealer that receives new certificates for its own account in
exchange for outstanding certificates must acknowledge that it will deliver a
prospectus in connection with any resale of the new certificates. See "Plan of
Distribution."
In addition, to comply with state securities laws, the new pass through
trust certificates may not be offered or sold in any state unless they have been
registered or qualified for sale in the state or an exemption from registration
or qualification is available and is complied with. The offer and sale of the
new pass through trust certificates to "qualified institutional buyers" (as
defined under Rule 144A of the Securities Act) is generally exempt from
registration or qualification under the state securities laws. We currently do
not intend to register or qualify the sale of the new pass through trust
certificates in any state where an exemption from registration or qualification
is required and not available.
RATIO OF EARNINGS TO FIXED CHARGES
For the year ended December 31, 2000, the ratio of our earnings to fixed
charges was 5.43. For the period from December 17, 1999 through December 31,
1999, the ratio of our earnings to fixed charges was 0.38. Because we began
operations on December 17, 1999, we cannot calculate a ratio of earnings to
fixed charges for any prior periods. For the purposes of calculating the ratio
of earnings available to cover fixed charges:
- earnings consist of income from continuing operations and fixed charges,
and
- fixed charges consist of interest on borrowings, related amortization and
estimated interest component of rent expense.
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USE OF PROCEEDS
We will not receive any proceeds from the issuance of the new certificates
offered in this exchange offer. In consideration for issuing the new
certificates as contemplated in this prospectus, we will receive in exchange old
certificates in like principal amount.
The old certificates surrendered in exchange for new certificates will be
retired and cancelled and cannot be reissued. Accordingly, issuance of the new
certificates will not result in a change in our lease rental obligations or any
increase in our indebtedness.
The old certificates were issued and sold in order to provide the debt
portion of the lease transactions we entered into with respect to our interests
in the Colstrip facility. The proceeds from the sale of the existing pass
through trust certificates were $338 million and were used by the pass through
trustee to purchase the lessor notes that were issued by the owner lessors that
acquired our interests in the Colstrip facility. The owner lessors used the
proceeds of the issuance of the lessor notes, together with the proceeds of
equity investments made in the owner lessors by the institutional investors that
formed the owner lessors, to finance their purchase of our interests in the
Colstrip facility and for lease related transaction expenses, including the
underwriting fees for the certificates.
The aggregate purchase price of our electricity generating facilities was
approximately $767 million which included a $760 million payment to MPC and $7
million for transaction expenses related to the acquisition of our electricity
generating facilities. The owner lessors paid an aggregate of $422.3 million to
acquire their interests in the Montana portfolio and to fund transaction costs
(approximately $410 million in respect of the Montana portfolio, and
approximately $12.3 million in respect of transaction costs). The institutional
investors that formed the owner lessors made equity contributions to the owner
lessors equal to $84.3 million (20% of the total cost of the interests in the
Montana portfolio purchased by the owner lessors and the transaction costs
funded by the owner lessors) and the balance of the amount paid by the owner
lessors, $338 million (80% of such cost), was financed through the issuance by
each owner lessor of the lessor notes. We paid the balance of the purchase price
of our electricity generating facilities and the balance of the transaction
expenses using equity contributions that we received from PPL Corporation.
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SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth our selected historical data. We had no
assets or operations prior to our acquisition of the Montana portfolio. All of
our generating facilities were acquired from MPC on December 17, 1999. The
selected historical information has been derived from our audited financial
statements included elsewhere in this prospectus. You should read the
information set forth below in conjunction with both the "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
section of this prospectus and our historical financial statements and the
accompanying notes included in this prospectus. No financial statements of the
pass through trust are included in this prospectus since the property of the
pass through trust consists solely of the lessor notes and because distributions
by the pass through trust depend on the rental and other payments that we make
under the leases.
FOR THE PERIOD FOR THE YEAR
DECEMBER 17, 1999 ENDED
TO DECEMBER 31, 1999 DECEMBER 31, 2000
-------------------- --------------------
(DOLLARS IN THOUSANDS)
STATEMENT OF INCOME DATA (FOR THE PERIOD):
Operating Revenues..................................... $ 9,713 $ 429,384
Operating costs and other expenses, less
depreciation........................................ 8,213 226,136
Depreciation expense................................... 734 13,186
Allowance for doubtful trade accounts receivable....... -- 18,695
Interest expense....................................... 2,005 25,764
Income tax expense (benefit)(1)........................ (399) 57,885
Extraordinary loss (net of income taxes)............... -- 1,005
Net income (loss)...................................... (840) 86,713
BALANCE SHEET DATA (AT THE END OF THE PERIOD):
Total assets........................................... 912,587 695,947
Long-term debt......................................... 5,000 --
Total liabilities...................................... 495,985 242,632
Member's equity........................................ 416,602 453,315
STATEMENT OF CASH FLOW DATA (FOR THE PERIOD):
Net cash provided (used) by operating activities....... (1,987) 100,233
Net cash provided (used) by investing activities....... (760,000) 396,021
Net cash provided (used) by financing activities....... 764,915 (420,000)
OTHER DATA (FOR THE PERIOD):
Capital expenditures................................... 83 13,979
Generation (MWh)....................................... 382,207 8,195,300
Ratio of earnings to fixed charges..................... 0.38 5.43
- ---------------
(1) We are a limited liability company and elected to be disregarded as a
separate entity for federal income tax purposes. Our member is responsible
for the income tax liability resulting from our operations in accordance
with an intercompany tax sharing policy between our member and its parent.
The income tax provision has been reflected in our consolidated financial
statements in accordance with Statement of Financial Accounting Standards,
or SFAS, 109, "Accounting For Income Taxes."
Our capitalization as of December 31, 2000 consists of approximately $453
million of member's equity. We have entered into operating leases totaling $410
million, and our rent obligations under the leases are treated as operating
lease payments for financial reporting purposes. Our future minimum rent
obligations under the leases are $43.3 million for 2001, $49.3 million for 2002,
$47.0 million for 2003, $43.5 million for 2004, $38.1 million for 2005 and a
total of $530.9 million for the remaining term of the certificates.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
GENERAL
We were formed to acquire, own, lease and operate the Montana portfolio.
The aggregate purchase price for the Montana portfolio, which we acquired on
December 17, 1999, was $767 million, which included a $760 million payment to
MPC and $7 million for transaction expenses. We funded the acquisition with a
$402 million indirect equity contribution from PPL Corporation and a $365
million draw under our credit facility. After the acquisition closed, PPL
Corporation made additional indirect equity contributions to us of approximately
$15 million.
The owner lessors paid us an aggregate amount of approximately $410 million
for the leased assets. This amount was funded by equity contributions from the
owner investor to the owner lessors in the amount of $72 million and $338
million from the proceeds from the sale of the lessor notes. We used $410
million of the proceeds from the sale of the leased assets to: (1) repay
principal and interest outstanding under our credit facility of approximately
$360 million; and (2) distribute to PPL Montana Holdings for ultimate
distribution to PPL Corporation approximately $50 million. In addition, the
owner investors, directly or through the owner lessors, paid $12.3 million of
the transaction expenses associated with the lease transactions.
As described above, PPL Corporation has already made a total of $417
million in indirect equity contributions to fund the acquisition. PPL
Corporation is also required to provide us with an additional indirect equity
contribution of a maximum of $97 million to fund the purchase of a portion of
MPC's interest in the Colstrip transmission system which we are negotiating to
acquire.
Through June 2002, we expect to sell approximately 60% of the energy that
we generate to MPC under two energy purchase agreements entered into in
connection with our acquisition of the Montana portfolio. These energy purchase
agreements should provide us with a revenue base as our energy marketing effort
is implemented and are expected to contribute approximately 25% of our revenues
over the remaining terms of the agreements. The energy purchase agreement
related to energy generated by Colstrip unit 3 covers a 200 MW load and expires
on December 17, 2001. The other energy purchase agreement requires us to supply
MPC's actual remaining customer load with energy generated by the other
generating facilities in the Montana portfolio. This agreement expires when
MPC's remaining customer load is zero, but in no event later than June 30, 2002.
Based on our recent estimates, we will supply a gradually increasing load
through June 30, 2002.
RESULTS OF OPERATIONS
We have a limited operating history. Separate financial statements for the
Montana portfolio are available only for the period since our acquisition of the
Montana portfolio. Prior to that, the portfolio's operations were fully
integrated with MPC's operations. Therefore, the Montana portfolio's results of
operations were consolidated into the financial statements of MPC. In addition,
the energy generated by the Montana portfolio was sold based on rates set by
regulatory authorities.
For purpose of the following discussion, we refer to the period from the
date of acquisition of the Montana portfolio, December 17, 1999, to December 31,
1999 as the initial period. We refer to the twelve month period ended December
31, 2000 as year 2000. The results of operations for these periods are discussed
below:
Revenues
Our revenues were $9.7 million for the initial period and $429.4 million
for year 2000. The initial period revenues consisted of $9.6 million of energy
revenues and $0.1 million of other revenues. Year 2000 revenues consisted of
$426.4 million of energy revenues and $3.0 million of other revenues.
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Operating costs
Operating costs were $8.2 million for the initial period and $244.8 million
for year 2000. Operating costs consist mainly of expenses for fuel, energy
purchases, transmission tariffs, plant operations and maintenance and general
and administrative expenses. Fuel expenses for the initial period were $1.4
million and $32.2 million for year 2000. Fuel expenses are principally the costs
of coal and fuel oils used in the operations of the generating facilities.
Energy purchases were $1.0 million for the initial period and $91.9 million for
year 2000. Energy purchases are principally to meet our energy supply
obligations.
Other operations and maintenance expenses were $4.1 million for the initial
period and $75.6 million for year 2000. These expenses consist principally of
labor and benefits, maintenance, parts, supplies and services expenses. Year
2000 expenses include approximately $9.1 million of rent expense related to the
operating lease on the Colstrip facility.
Depreciation expense
Depreciation expense was $0.7 million for the initial period and $13.2
million for year 2000. Depreciation expense primarily relates to the generating
assets purchased from MPC.
Allowance for doubtful trade accounts receivable
Allowance for doubtful trade accounts receivable was $18.7 million for year
2000. The expense primarily relates to receivables from the California
Independent System Operator. No allowance was required for the initial period.
Interest expense
Interest expense was $2.0 million for the initial period and $25.8 million
for year 2000. The interest expense relates to interest on the credit facility,
which includes the bridge and working capital facilities, amortization of
related financing costs and interest upon accretion of wholesale energy
commitments. The weighted average interest rate on the facilities was 8.62% for
the initial period and 7.26% for year 2000. The principal amount owed under the
facilities was $370 million as of December 31, 1999 and $0 at December 31, 2000.
Income tax expense (benefit)
Income tax benefit was $0.4 million for the initial period. The income tax
expense was $57.9 million for year 2000. The effective tax rate was 32.2% for
the initial period and 39.8% for year 2000.
Extraordinary item
During 2000, we repaid our bridge financing debt and reduced the
commitments under the revolving credit facility. In accordance with SFAS No. 4,
"Reporting Gains and Losses from Extinguishment of Debt," an extraordinary loss
at approximately $1,005,000, net of $653,000 of income tax benefit, was recorded
in write off deferred loan fees.
LIQUIDITY AND CAPITAL RESOURCES
Net cash used by operating activities for the initial period was $2.0
million. Net cash provided by operating activities was $100.2 million for year
2000. Net cash used by investing activities was $760 million for the initial
period. Net cash provided by investing activities was $396.0 million for year
2000. The cash flow from investing activities for year 2000 includes $410
million of proceeds from the sale of the leased assets. Net cash provided by
financing activities was $764.9 million for the initial period. Net cash used by
financing activities was $420.0 million for year 2000. The cash flow from
financing activities for the initial period included an equity contribution of
$394.9 million and net borrowings of $370 million. The cash flow from financing
activities for year 2000 includes repayment on the bridge facility of $365
million and distribution to member of $50.0 million.
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We are required to make semi-annual rent payments under the leases on each
January 2 and July 2 during the terms of the leases, beginning on January 2,
2001. Our future minimum rent obligations under the leases are $43.3 million for
2001, $49.3 million for 2002, $47.0 million for 2003, $43.5 million for 2004,
$38.1 million for 2005 and a total of $530.9 million for the remaining term of
the certificates. As a result of these obligations, a substantial portion of our
cash flow from operations will be dedicated to payments of rent under the
leases. We are also required to make payments of operating expenses and other
expenses, including interest on and principal of our outstanding debt under our
working capital facility.
We expect to make continued capital expenditures for the Montana portfolio.
The average capital expenditures we expect to make are approximately $15 million
per year. Compliance with environmental standards will continue to be reflected
in our capital expenditures and operating costs. We believe that cash flow from
our operations will be sufficient to cover aggregate rent payments under the
leases and, together with borrowings under our working capital facility, to
cover expected capital expenditure requirements. If the cash flow from our
operations is not sufficient, any unanticipated capital expenditures could
adversely affect our cash flow from operations and operating income in the
period incurred.
SEASONALITY
Because hydroelectric generating facilities represent a substantial portion
(42%) of the installed capacity in the Western Systems Coordinating Council,
wholesale energy prices have historically been lower in the first six months of
the calendar year due to high seasonal water flow conditions. In addition,
energy available from the Corette and Colstrip facilities has been lower during
the first six months of the calendar year due to the timing of scheduled
maintenance outages. These historical market, water flow and maintenance
patterns may cause our revenues to be lower in the first six months of the
calendar year.
SALES TO CALIFORNIA INDEPENDENT SYSTEM OPERATOR
Starting in mid-December 2000 the U.S. Secretary of Energy ordered a number
of wholesale power sellers in the western United States, including us, to sell
to the California Independent System Operator all amounts of energy that such
sellers had available in excess of their existing firm power commitments. The
orders required that the California Independent System Operator first certify on
a daily basis to the Department of Energy that it had inadequate energy supplies
to meet its needs, and that it was implementing specified conservation measures.
If these certifications were made, then the California Independent System
Operator was authorized to request deliveries of excess energy from the sellers
named in the orders. The orders stated that the California Independent System
Operator was to allocate such requests, to the extent feasible, in proportion to
each seller's available excess power.
The U.S. Secretary of Energy has stated that he took this extraordinary
action because of an emergency that he found exists in California due to a
shortage of electric energy in the state. We have requested rehearing of these
orders on the ground that they fail to provide adequate assurances that the
sellers would be paid for the power so delivered. Rehearing was granted on
January 17, 2001 for the limited purpose of receiving additional information.
The most recent such order expired on February 7, 2001.
From mid-December through the expiration of the order, we delivered
approximately 1,700 MWh to the California Independent System Operator pursuant
to these orders. The delivered energy represents approximately 0.2% of our
production for the period the orders were in place. We have not yet received
payment for these sales. We negotiated prices for a portion of the ordered sales
with the California Independent System Operator. The prices for the remaining
ordered sales, which occurred in 2001, will be established in future proceedings
at the Federal Energy Regulatory Commission. If the Federal Energy Regulatory
Commission accepts our proposals for the pricing of these sales, which we
caution cannot be assured, we estimate that the value of the energy we have sold
under the U.S. Secretary of Energy's orders amounts to about $0.4 million as of
February 16, 2001.
In addition, in December 2000 we made voluntary sales of energy to the
California Independent System Operator prior to the date the first order was
issued. The pre-order sales amount to about $18 million and are currently
scheduled to be paid in February and March of 2001.
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Our ability to be paid for both our pre-order and post-order sales to the
California Independent System Operator will ultimately depend on the two major
California electric utilities, Pacific Gas and Electric Company and Southern
California Edison Company, recovering their financial stability, or on the State
of California constructing a financial solution to the power supply crisis
currently facing the state. Both of the utilities are experiencing severe
liquidity constraints, have defaulted on various debts and have stated publicly
that they may file for bankruptcy protection. We cannot predict if or when we
will receive payment for sales to the California Independent System Operator
that we have made or may be required to make in the future, or the final amounts
of any such payments. As of December 31, 2000 we have fully reserved for
possible underrecoveries of payments for these energy sales. We may have to add
to our reserves in future periods if we are required by the U.S. Secretary of
Energy or other authority to continue to supply the California Independent
System Operator. Litigation arising out of the California supply situation has
been filed at the Federal Energy Regulatory Commission and in California courts
against sellers of energy to the California Independent System Operator. The
plaintiffs and intervenors allege abuse of market power, among other things, and
seek price caps on wholesale sales in California and other Western power
markets, refunds of excess profits allegedly earned on these sales, and other
relief, including treble damages and attorneys' fees. We have intervened in the
Federal Energy Regulatory Commission proceedings in order to protect our
interests, but have not been named as a defendant in any of the court actions.
We cannot predict whether we will eventually be named in these lawsuits or other
lawsuits and cannot predict the outcome of any such litigation. If the eventual
resolution of the California power supply crisis involves the imposition of
price caps or other regulatory controls on wholesale energy sales, our future
cash flow and financial condition could be adversely affected.
CREDIT FACILITY
On November 16, 1999, we entered into a credit facility with various
commercial banks and The Chase Manhattan Bank as administrative agent for the
banks. The credit facility included:
- a $360 million bridge facility, which we repaid with the proceeds from
the sale of the leased assets and cancelled;
- a revolving acquisition facility, which we have cancelled; and
- a working capital facility of up to $100 million, which we use for our
general corporate purposes.
NEW ACCOUNTING STANDARDS
On January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133 requires that every derivative
instrument be recorded on the balance sheet as an asset or liability measured at
its fair value and that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. We,
through the use of a cross-functional project team, have completed the process
of identifying all derivative instruments, determining their fair market values,
designating and documenting hedge relationships and evaluating the effectiveness
of those hedge relationships.
In accordance with the transition provisions of SFAS 133, we expect to
record a net-of-tax cumulative-effect-type charge of $155,998,000 in accumulated
other comprehensive income to recognize at fair value all derivatives that are
designated as cash flow hedging instruments. This adjustment will be attributed
to financial swaps in which we have reserved and stand ready to deliver energy
from the planned output of our generating units. We use these contracts to
mitigate commodity price risk.
Future changes in the fair market values of these derivative instruments,
to the extent that the hedges are effective at mitigating the underlying
commodity risk, will be recorded in other comprehensive income. At the date the
underlying transaction occurs, the amounts accumulated in other comprehensive
income will be reported in the Consolidated Statements of Income. To the extent
that the hedges are not effective, the ineffective portion of the changes in the
fair market value will be recorded directly in earnings. We expect to reclassify
into earnings during the next twelve months $119,710,000 from the transition
adjustment that will be
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recorded in accumulated other comprehensive income. The cash flow hedges
described above cover various periods of time from January 2001 through December
2006.
MARKET RISK SENSITIVE INSTRUMENTS
We actively manage the market risks inherent in our business. The board of
directors of PPL Corporation has adopted a risk management policy to manage risk
exposure. The policy establishes a risk management committee comprised of
certain executive officers, which oversees the risk management function.
Nonetheless, adverse changes in commodity prices and interest rates may result
in losses in earnings, cash flows and/or fair values. The forward-looking
information presented below only provides estimates of what may occur in the
future, assuming certain adverse market conditions, due to reliance on model
assumptions. As a result, actual future results may differ materially from those
presented. These disclosures are not precise indicators of expected future
losses, but only indicators of reasonably possible losses.
Commodity Price Risk
Our risk management program is designed to manage the risks associated with
market fluctuations in the price of electricity. Our risk management policy and
programs include risk identification and risk limits management, with
measurement and controls for real time risk monitoring. In 2000, we entered into
fixed price forward contracts that require physical delivery of the commodity
and derivative financial instruments consisting mainly of financial swaps where
settlement is generally based on the difference between a fixed and index based
price for the underlying commodity. We expect to continue using such contracts
through 2000. At December 31, 1999, we did not have such contracts in place.
We enter into contracts to hedge the impact of market fluctuations on our
energy-related assets and liabilities. In addition as defined by EITF 98-10, we
may enter into these contracts for trading purposes to take advantage of market
opportunities. We may at times create a net open position in our portfolio that
could result in significant losses if prices do not move in the manner or
direction anticipated.
We use various methodologies to simulate forward price curves in the energy
markets to estimate the size and probability of changes in market value
resulting from commodity price movements. The methodologies require several key
assumptions, including selection of confidence levels, the holding period of the
commodity positions, and the depth and applicability to future periods of
historical commodity price information. At December 31, 2000, we estimated that
a 10% adverse movement in market prices across the market we operate in and
across all time periods could have decreased the value of our trading portfolio
by approximately $0.3 million. For our non-trading portfolio, a 10% adverse
movement in market prices across the markets we operate in and across all time
periods could have decreased the value of our non-trading portfolio by
approximately $42.6 million at December 31, 2000. However, this effect would
have been offset by the change in the value of the underlying commodity, that
is, the electricity generated. In addition to commodity price risk, our
commodity positions are also subject to operational and event risks including,
among others, increases in load demand and forced outages at generating plants.
Interest Rate Risk
We may use borrowings to provide funds for our operations. We utilize
various risk management instruments to reduce our exposure to adverse interest
rate movements through the use of financial derivative products to adjust the
mix of fixed and floating-rate interest rates in our debt portfolio. We have
risk limits designed to balance risk exposure to volatility in interest expense
and losses in the fair value of our debt portfolio due to changes in the
absolute level of interest rates. We have no borrowings outstanding as of
December 31, 2000. Based on the level of outstanding borrowings, the interest
rate risk is not material to our operations and cash flows as of December 31,
2000.
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ABOUT US
PPL MONTANA AND ITS SUBSIDIARIES
We are a Delaware limited liability company and an indirect wholly owned
subsidiary of PPL Corporation. We were formed on December 29, 1998 to acquire,
own, lease and operate the Montana portfolio. Our business consists solely of
the ownership, leasing and operation of the Montana portfolio, the execution of
the lease transactions and related activities. The mailing address of our
principal executive offices is 303 North Broadway, Suite 400, Billings, Montana
59101, and our telephone number is (406) 869-5100.
PPL CORPORATION
Our ultimate parent, PPL Corporation, is a holding company with
headquarters in Allentown, Pennsylvania. Its subsidiaries include, among others:
- PPL Electric Utilities Corporation (formerly PP&L, Inc.), which provides
energy delivery services in eastern and central Pennsylvania;
- PPL Capital Funding, Inc., which engages in financing activities for some
of PPL Corporation's unregulated subsidiaries;
- PPL Energy Funding, which is a holding company for PPL Corporation's
subsidiaries involved in regulated and unregulated domestic and
international energy generation and delivery;
- PPL Global, LLC, which is the development and international operations
affiliate of PPL Corporation;
- PPL EnergyPlus, which markets wholesale and retail energy in 43 states
and Canada and is our agent for the marketing of energy generated by the
Montana portfolio;
- PPL Generation, LLC, which is our indirect parent company and serves as
the holding company for PPL Corporation's generating businesses and
assets in the United States; and
- PPL Montana Holdings, which is our direct parent company and holds all of
our membership interests.
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The following chart shows the ownership structure of PPL EnergyPlus and us.
[PPL EnergyPlus Chart]
Our acquisition of the Montana portfolio represents an important step
towards PPL Corporation's goal of becoming a major multi-regional energy
company. The Montana portfolio gives PPL Corporation access to energy markets in
the Western Systems Coordinating Council that are in the process of
deregulating.
PPL Corporation's subsidiaries, including us, own or lease generating
facilities in the United States having approximately 12,400 MW of energy
generation capacity, including generating facilities in operation, in
construction and under active development.
PPL EnergyPlus sells energy, natural gas and energy services to retail
customers and serves as supplier of choice for customers in Pennsylvania, New
Jersey, Maine, Montana and Delaware.
None of our obligations under the leases are obligations of, or guaranteed
by, PPL Corporation or any of its affiliates, other than us.
PPL Corporation's common stock is traded on the New York Stock Exchange.
PPL Corporation files periodic reports with the Securities and Exchange
Commission. PPL Corporation's SEC filings are available to the public from the
SEC's web site at http://www.sec.gov.
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BUSINESS
INDUSTRY OVERVIEW
The United States energy industry, which includes companies engaged in
providing energy generation, transmission and distribution as well as ancillary
services, has undergone substantial deregulation over the last several years,
leading to significantly increased competition. Historically, local energy
utilities provided generation, transmission and distribution services to their
retail service territories under exclusive franchises and recovered costs plus a
rate of return on invested capital based upon rate orders approved by a
regulatory body. In recent years, independent energy producers have sold energy
to utilities on a contractual basis.
The Energy Policy Act introduced more competition into the industry by
creating exempt wholesale generators, a new class of generators that are not
subject to significant portions of the regulatory structure otherwise generally
applicable to energy utilities and their holding companies. It also empowered
the Federal Energy Regulatory Commission to require that the owners and
operators of energy transmission facilities make their transmission facilities
available on a nondiscriminatory basis to all wholesale generators, sellers and
buyers of energy.
In addition to making transmission facilities available to wholesale
customers, state regulators throughout the United States have begun to establish
a framework to allow retail customers to choose their energy suppliers, with
incumbent utilities required to deliver that energy over their transmission and
distribution systems. Various states are in different stages of the process of
determining a framework for deregulation.
As part of the transition to a deregulated market, a number of energy
utilities nationwide have divested or are in the process of divesting all or a
portion of their energy generating business. Legislative and regulatory
developments, increased competition and an increasing focus on shareholder value
are responsible for these changes. As additional companies seek to expand into a
more deregulated market, the industry is likely to see increasing consolidation
and the emergence of dominant companies, which will intensify competition.
Energy generation and energy marketing have been the means by which these
companies seek to achieve higher returns than their regulated utility
predecessors. The emerging regulatory environment of our industry is also likely
to increase competition in the future and may result in lower energy prices and
less profit for all competitors in the energy generating industry.
MARKET OVERVIEW
Western Systems Coordinating Council
The United States is divided into ten regional reliability councils whose
polices are coordinated by the North American Electric Reliability Council.
These regional councils are responsible for overseeing the reliable operation of
the energy system. The Western Systems Coordinating Council is geographically
the largest of the ten regional councils and is on the forefront of deregulation
in the United States. The Western Systems Coordinating Council is composed of
all or portions of 14 states in the western United States. It encompasses 1.8
million square miles and reaches approximately 59.7 million people in the United
States, or 21.4% of all United States residents.
According to the independent market consultant, the Western Systems
Coordinating Council relies significantly on hydroelectric and coal-fired
generation. Of approximately 158,400 MW of installed energy generation capacity
in the Western Systems Coordinating Council, 42% is hydroelectric and 23% is
coal-fired. The Montana portfolio represents less than 1% of the installed
energy generation capacity in the Western Systems Coordinating Council.
Most of the states and markets in the Western Systems Coordinating Council
have recently completed, or are undergoing, energy supply deregulation at the
wholesale and retail level. Competitive energy supply markets are replacing
heavily regulated markets. In general, energy supply markets in the Western
Systems Coordinating Council, and particularly in Montana, are based on
bilateral contracts. In other words, these markets function through direct
contracts between energy generators and energy purchasers. Some markets within
the Western Systems Coordinating Council, however, such as California, have
opted for market
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structures based more on short-term purchases on the open market for immediately
available energy, also known as the spot market, and sales through recently
established power exchanges.
California, the largest state in the Western Systems Coordinating Council,
was the first state in the United States to deregulate. Montana was the second
state in the western United States to deregulate. In both Arizona and Nevada,
restructuring legislation has been passed and retail open access is being phased
in for industrial, commercial and residential customers over the course of the
remainder of 2001. Oregon has recently enacted utility restructuring legislation
which provides Oregon nonresidential energy consumers with direct access to
competitive energy markets not later than October 1, 2001 and requires the
Oregon Public Utility Commission to report to the Oregon legislature not later
than January 1, 2003 whether residential consumers would benefit from direct
access.
The Western Systems Coordinating Council is separated into four distinct
sub-regions that represent geographic and climatic differences. The sub-regions
are (1) the Northwest Power Pool, which includes Idaho, Montana, northern
Nevada, Oregon, Utah, Washington and western Wyoming, (2) the Rocky Mountain
power area, (3) the Arizona-New Mexico-Southern Nevada power area, and (4) the
California power area. Of these areas, the Northwest Power Pool and California
are the largest markets for energy.
Montana
The Montana market is a bilateral market. The customer base in the Montana
market includes municipalities, retail aggregators, energy marketers and
commercial and industrial end-users. Montana enacted a deregulation law which
will make retail customer direct access available for all energy customers by
June 30, 2002.
MPC previously supplied energy to approximately 86% of the population of
Montana, or approximately 756,000 customers, with energy generated from the
Montana portfolio. Most of these customers currently remain customers of MPC.
MPC supplies these customers with energy generated by and purchased from us
under the energy purchase agreements that we have with MPC.
Under the deregulation law passed in Montana, these customers must select
an alternative energy supplier by June 30, 2002. Montana has not yet implemented
the default supplier provisions in the deregulation law. Default supplier
provisions will designate a default supplier of energy for those customers who
do not select an alternative energy supplier by June 30, 2002. On October 27,
2000, the Montana Public Service Commission issued a proposal to extend the
transition period for election of customer choice to July 1, 2004, and sought
comments upon such proposed action by November 17, 2000. It is too early to
predict the outcome and scope of the final action that will be taken by the
Commission, although it appears likely that the transition period will be
extended. Such an extension would also continue MPC (or its successor) as the
default supplier during the extended transition. It is also possible that the
2001 Montana legislature will deal with the issue in some manner.
Large industrial customers may select an alternative supplier under the
Montana deregulation law. These customers represent a substantial portion of the
competitive retail market in Montana and are significant because they require a
substantial amount of energy on a consistent basis. Energy generated from our
generating facilities represents a significant portion of the capacity available
in Montana. Due to our competitive cost of supply and the transmission
constraints on the export and import of energy into the Montana market, we
expect to supply many of these customers under arrangements with PPL EnergyPlus
using energy generated by the Montana portfolio.
The Northwest
Our primary market outside Montana is the wholesale energy market in the
remainder of the Northwest, which is well developed with large quantities of
energy being exchanged on a regular basis. The Northwest relies extensively on
hydroelectric generation and, to a lesser extent, on coal-fired generation.
According to the independent market consultant, hydroelectric generation
accounts for approximately 60% of the energy produced in the Northwest, based on
the average hydroelectric generation for the last ten years and coal-fired
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generation accounts for approximately 26% of annual energy produced in the
Northwest. The Bonneville Power Administration supplies about 40% of the
Northwest's energy. By comparison, the Montana portfolio represents
approximately 2% of the energy produced in the Northwest. Historically, the
Northwest has been a net exporter of energy to other areas of the Western
Systems Coordinating Council, primarily California.
While there is no independent power pool in the Northwest as in California
or the northeastern part of the United States, utilities and public agencies
have traded energy in the region for more than 30 years under the Western
Systems Power Pool operating agreement or Federal Energy Regulatory Commission
approved bilateral agreements. Approximately 90% of the transactions take place
under these preapproved standard form agreements. The Western Systems Power Pool
operating agreement was amended in 1998 to allow transactions to be consummated
at "market-based" rates; prior to this amendment, the agreement capped the rates
at which sales could be made under the agreement.
California
The secondary target market for the energy we export from Montana is
California. Since deregulating in 1997, California has implemented an
independent system operator and commenced operation of the California Power
Exchange. The California Power Exchange has active day-ahead and hour-ahead
energy trading markets.
OUR PLAN AND STRATEGY
THE MONTANA PORTFOLIO
In June 1997, the Montana state legislature enacted a bill which
deregulated the energy generating business and initiated customer choice for
competitive energy supplies effective July 1, 1998. In response to this
legislation, in March 1998, MPC initiated an auction to divest its generating
assets.
PPL Global, a direct subsidiary of PPL Energy Funding, was selected as the
winning bidder in this auction process. In October 1998, PPL Global entered into
an asset purchase agreement with MPC under which PPL Global agreed to acquire
the Montana portfolio for a purchase price of approximately $760 million plus
transaction expenses. PPL Global subsequently assigned its interests in the
asset purchase agreement to us, and we closed the acquisition of the Montana
portfolio on December 17, 1999. We have an obligation under this asset purchase
agreement to acquire the portion of MPC's interest in the Colstrip transmission
system associated with Colstrip units 1, 2 and 3. Negotiations to complete this
acquisition are ongoing. On July 20, 2000, we sold our interests in the Colstrip
facility and leased the interests back.
The independent engineer's report includes a detailed description of the
generating facilities included in the Montana portfolio. The following table
summarizes some of the key aspects of these facilities:
NET CAPACITY COMMERCIAL
FACILITY (MW) TYPE OF FACILITY OPERATION DATE LOCATION
-------- ------------ ---------------- -------------- --------------------
Colstrip units 1 and 2.... 307(1) Coal-fired 1975 and 1976, Colstrip
respectively
Colstrip unit 3........... 222(1) Coal-fired 1984 Colstrip
Corette................... 154 Coal-fired 1968 Billings
Kerr...................... 189(2) Hydroelectric) 1939 Columbia River Basin
(run of river
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NET CAPACITY COMMERCIAL
FACILITY (MW) TYPE OF FACILITY OPERATION DATE LOCATION
-------- ------------ ---------------- -------------- --------------------
Thompson Falls............ 86(2) Hydroelectric) 1915, new unit Columbia River Basin
(run of river 1995
Mystic.................... 11(2) Hydroelectric) 1927 West Rosebud Creek
(run of river
Madison................... 9(2) Hydroelectric) 1906 Missouri -- Madison
(run of river River Basin
Hauser.................... 17(2) Hydroelectric) 1911 Missouri -- Madison
(run of river River Basin
Holter.................... 50(2) Hydroelectric) 1918 Missouri -- Madison
(run of river River Basin
Black Eagle............... 18(2) Hydroelectric) 1927 Missouri -- Madison
(run of river River Basin
Rainbow................... 35(2) Hydroelectric) 1910 Missouri -- Madison
(run of river River Basin
Cochrane.................. 54(2) Hydroelectric) 1958 Missouri -- Madison
(run of river River Basin
Ryan...................... 60(2) Hydroelectric) 1915 Missouri -- Madison
(run of river River Basin
Morony.................... 48(2) Hydroelectric) 1929 Missouri -- Madison
(run of river River Basin
-----
Total........... 1,260MW
- ---------------
(1) Based on our percentage entitlements under the Colstrip ownership
agreements.
(2) The hydroelectric generating facilities together generate up to 577 MW of
energy in the summer. In the winter, these facilities historically generate
approximately 474 MW of energy due to lower average water flow conditions.
The environmental impact from the operation of our thermal generating
facilities is mitigated through the use of pollution control equipment. Colstrip
units 1 and 2 are equipped with flue gas scrubbers for SO(2) removal. Each unit
is equipped with three scrubber vessels. Colstrip units 3 and 4 are also
equipped with flue gas scrubbers and each unit has eight scrubber vessels. The
Corette facility burns low-sulfur coal, has low NO(x) burners and electrostatic
precipitators for particulate removal.
TRANSMISSION INTERCONNECTIONS
We have access to transmission throughout Montana, including to
transmission routes to the northwest, southwest and southeast. The current
transmission infrastructure of, and regional coordination by, the Western
Systems Coordinating Council enables us to transmit energy throughout the
western United States by either Federal Energy Regulatory Commission mandated
open-access tariffs or by transmission agreements. We expect to maintain the
existing interconnections to the MPC transmission grid, subject to an
interconnection agreement with MPC.
We can deliver the energy we generate from the Colstrip facility through
the Colstrip transmission system and the Bonneville Power Administration Montana
intertie, each discussed below, to the adjacent transmission systems of Idaho
Power, Avista, Western Area Power Administration and PacifiCorp. We can then
transmit our energy over those entities' transmission systems, which provide
additional corridors to the south and the east. MPC also has a DC tie to the
Eastern Interconnect at Miles City, Montana which may allow us to capitalize on
price differentials, if available, between the Western Systems Coordinating
Council and the Mid-Continent Area Power Pool. We have access to all of MPC's
transmission capacity for energy that we generate at all of our generating
facilities through our interconnection agreement with MPC and MPC's open-access
transmission tariff.
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The Colstrip transmission system includes each of the following:
- two 500 kV AC transmission lines ("A" and "B") from the Colstrip 500 kV
switchyard to the Broadview, Montana substation, a distance of
approximately 116 miles;
- two 500 kV AC transmission lines ("1" and "2") from the Broadview
substation to Townsend, Montana, a distance of approximately 133 miles;
- the 500 kV facilities at the Colstrip switchyard except for those
included in the generating units; and
- the 500 kV facilities at Broadview, Montana.
The ownership interests in the Colstrip transmission system are
contractually specified in the Colstrip project transmission agreement for each
Colstrip transmission system owner for each of these segments. The Colstrip
transmission system connects at Townsend with the Bonneville Power
Administration's double circuit line which extends to Garrison, Montana. The
Bonneville Power Administration's 85-mile double-circuit 500 kV transmission
line extending from the terminal point of the Colstrip transmission system near
Townsend, Montana to a Bonneville Power Administration substation located on the
Federal Columbia River Transmission System near Garrison, Montana is known as
the Bonneville Power Administration Montana intertie. The Bonneville Power
Administration owns and operates the Bonneville Power Administration Montana
intertie. All energy transmitted across the Colstrip transmission system for
export out of the state of Montana requires transmission across the Bonneville
Power Administration Montana intertie.
Our asset purchase agreement with MPC provides that we are to purchase the
portion of MPC's interest in the Colstrip transmission system associated with
Colstrip units 1, 2 and 3 for $97 million. This interest would provide us with
612.8 megawatts of transmission allocation between Colstrip and Broadview,
Montana, and 210 megawatts of transmission allocation between Broadview and
Townsend, Montana. We are currently in discussions with MPC to pursue
alternatives to acquiring this entire interest in the Colstrip transmission
system as contemplated by the asset purchase agreement because we are a
generating company and do not believe that we need to acquire that much
transmission capacity for our business purposes in light of the open-access
transmission tariffs available to us. These discussions are ongoing, so we
cannot predict whether we will buy all or less than all of MPC's entire interest
in the Colstrip transmission system, or what the purchase price will be if a
purchase occurs. We have a commitment from PPL Corporation to provide us with an
additional equity contribution of up to $97 million to fund the acquisition.
If we purchase an interest in the Colstrip transmission system from MPC
under the terms of the asset purchase agreement, we will also acquire 258.5 MW
of associated interest in the capacity of the Bonneville Power Administration
Montana intertie through assignment of the existing Bonneville Power
Administration Montana intertie agreements. These agreements are scheduled to
expire on September 20, 2027, but have 20-year renewal provisions. We expect
that these agreements will be extended on similar terms, conditions and pricing
thereafter. However, because we would only have access to 210 MW on the
Broadview -- Townsend segment of the Colstrip transmission system, our only
transmission route into Townsend, we would effectively be constrained to 210 MW
of capacity on the Bonneville Power Administration Montana intertie. We would
only pay charges associated with our transmission capacity of 210 MW on the
Bonneville Power Administration Montana intertie.
MPC is the operator of the Colstrip transmission system and it, or its
successor, will remain its operator under the Colstrip ownership and operating
agreements.
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Northwest regional transmission organization
Various transmission paths within the Northwest, and between the Northwest
and California and the Pacific southwest, are subject to periodic constraints.
As a result, at times it may be difficult for generating facilities and other
energy sellers in the region to obtain adequate transmission capacity to
transport energy to their desired markets. On December 20, 1999, the Federal
Energy Regulatory Commission issued its Order 2000, relating to the formation
and implementation of regional transmission organizations, or RTOs. The Federal
Energy Regulatory Commission's express objective in issuing the order is to
bring the transmission facilities of as many transmission owners (including
consumer-owned utilities and other non-Federal Energy Regulatory
Commission-jurisdictional entities) as possible under the operation and control
of regional transmission organizations. The regional transmission organization's
operation and control of the transmission facilities would, among other things,
eliminate or reduce the application of multiple additive rates for transmission
services and discriminatory market practices, and would enhance transmission
reliability, congestion management and system planning and expansion. Order 2000
requires that Federal Energy Regulatory Commission-jurisdictional transmission
owners file a proposal with the Federal Energy Regulatory Commission by October
15, 2000 on the efforts of such owners to participate in a regional transmission
organization that would become operational not later than December 15, 2001.
There is currently no operational regional transmission organization in the
Western Systems Coordinating Council outside of California. On October 23, 2000,
in response to Order 2000, the Bonneville Power Administration, Idaho Power,
Nevada Power Company, Sierra Pacific Power Company, MPC, Puget, Portland, Avista
and PacifiCorp, which we refer to as the filing utilities, made a supplemental
compliance filing with the Federal Energy Regulatory Commission proposing
formation of a regional transmission organization, to be called RTO West, which
would operate throughout the Northwest Power Pool and southern Nevada. On
October 16, 2000, all of the filing utilities except the Bonneville Power
Administration, Idaho Power and PacifiCorp made an Order 2000 compliance filing
with the Federal Energy Regulatory Commission proposing the formation of an
independent transmission company in connection with RTO West. The independent
transmission company, which would be a Delaware limited liability company named
TransConnect LLC, would own the aggregate transmission facilities of the
participating filing utilities, and would contract with RTO West to place these
facilities under the operational control of RTO West. The utilities seeking to
form the independent transmission company have asked the Federal Energy
Regulatory Commission for declaratory orders that the company as proposed would
satisfy the independence requirements established by the Federal Energy
Regulatory Commission in Order 2000 for regional transmission organizations and
would be entitled to perform transmission planning and expansion functions on
behalf of RTO West.
RTO West is proposed to take the form of an independent system operator,
which would operate, but not own, the transmission facilities under its control.
The filing utilities are structuring RTO West in this manner in part because any
effort by the Bonneville Power Administration to transfer ownership of its
transmission facilities to a transmission company would generate significant
resistance within the Northwest and would encounter serious legal obstacles. RTO
West would be a nonprofit Washington corporation, and would be governed by an
independent board of trustees. A stakeholder advisory committee, in which all
members of RTO West would be entitled to participate, would provide ongoing
advice and consultation to the board of trustees on a wide range of matters
relating to the regional transmission organization, including any proposed
amendments to the regional transmission organization's tariff. Although the
filing utilities have taken somewhat divergent positions on the extent of the
transmission facilities that they propose to place under the operational control
of RTO West, they have stated that RTO West would encompass all high-voltage
transmission facilities. RTO West would not initially include an associated
power exchange.
For purposes of preparing the RTO West Federal Energy Regulatory Commission
filing, the filing utilities mounted a substantial regional effort, involving
not only the filing utilities but also a broad range of other constituencies,
including representatives of the region's consumer-owned utilities, independent
energy producers, power marketers, industrial customers, residential customers,
state utility and energy regulatory offices, environmental groups and renewable
resources advocates. A 25-member regional representatives group (which included
representatives of generators and power marketers) was established to oversee
the filing effort, and a variety of open-membership work groups (including
transmission pricing, congestion manage-
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ment, ancillary services, transmission planning, seams, legal, market monitoring
and implementation work groups) were also formed for purposes of assisting in
the preparation of the Federal Energy Regulatory Commission filing documents.
The stated intent of the filing utilities in establishing the regional
representatives group was that decisions with respect to the structure and
operations of RTO West would be made by consensus within the open-membership
work groups and the regional representatives group to the maximum extent
practicable. However, the filing utilities reserved the right to make final
decisions themselves with respect to any matters which the work groups and the
regional representatives group were unable to resolve by consensus.
The RTO West filing made with the Federal Energy Regulatory Commission on
October 23, 2000 was only a partial filing, and therefore did not contain all of
the essential elements of the RTO West proposal. That filing included documents
relating to the governance of RTO West (principally the proposed articles of
incorporation and bylaws of the RTO), and proposed forms of the RTO West
transmission operating agreement, agreement to suspend provisions of
pre-existing transmission agreements, and agreement limiting liability among RTO
West participants, along with white papers describing the manner in which RTO
West is proposed to satisfy various of the characteristics and functions
required of regional transmission organizations under Order 2000. The filing
utilities are proposing to make a further compliance filing with the Federal
Energy Regulatory Commission in the summer of 2001, in which they would submit
the remaining RTO West documents required to be approved by the Federal Energy
Regulatory Commission, including the proposed forms of RTO West transmission
tariff, generation integration agreement, load integration agreement, scheduling
coordinator agreement and security coordinator agreement.
A variety of interventions and protests have been filed with respect to the
RTO West and TransConnect filings, and we have ourselves filed an intervention
and protest with respect to each filing as part of an ad hoc group of
independent power producers and power marketers styled as the Northwest
IPPs/Marketers Group. The protests have raised concerns regarding various
aspects of the proposed RTO West, including the allocation of voting power
within certain RTO West voting classes and the extent of TransConnect's
independence from market participants. The protest filed by the Northwest
IPPs/Marketers Group in the RTO West Federal Energy Regulatory Commission
proceeding focuses on three concerns:
(1) the proposed exclusion from the control of RTO West of certain power
lines and related facilities used for Federal Energy Regulatory
Commission-jurisdictional services. This proposed exclusion, if not
disallowed by the Federal Energy Regulatory Commission, could cause
transmission customers of RTO West, including us, to be subject to
multiple transmission rates, and therefore increased electric power
transportation costs, when moving power over any such excluded
facilities, and could also cause power producers such as ourselves to
be subject to potentially disparate and discriminatory interconnection
standards and requirements when seeking to interconnect generating
projects to any such excluded facilities;
(2) the extent to which independent power producers and power marketers
will be precluded from obtaining firm transmission rights on
constrained paths as a result of RTO West's proposed procedure for
allocating such rights on such paths to incumbent utility power
suppliers; and
(3) certain proposed limitations on the liability of RTO West for wrongful
dispatch instructions.
The protest filed by the Northwest IPPs/Marketers Group in the TransConnect
proceeding focuses on the appropriateness of TransConnect performing
transmission planning operations on behalf of RTO West. The Northwest
IPPs/Marketers Group has also requested that the Federal Energy Regulatory
Commission consolidate the RTO West and TransConnect proceedings, in view of the
extent of the overlap in the issues required to be resolved by the Federal
Energy Regulatory Commission in both proceedings.
Notwithstanding the size and scope of the RTO West filing effort, and the
significance of the resources that have been committed to it, we cannot predict
with any certainty whether this effort will result in the actual formation of
one or more RTOs in the Northwest, or, if any RTO is formed in the Northwest,
what the geographic scope, transmission pricing and ratemaking principles,
extent of control over transmission facilities and other characteristics of the
RTO would be.
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OUR ENERGY MARKETING STRATEGY
We market all of our energy in the Western Systems Coordinating Council.
The Northwest is our primary regional market within the Western Systems
Coordinating Council, and Montana is our single most important market, where we
currently sell approximately 80% of our output. We expect to continue to sell
approximately 80% of our output in Montana. We export the remainder of our
output to a number of markets. These markets include the remainder of the
Northwest, California and elsewhere in the Western Systems Coordinating Council.
We have developed a comprehensive energy marketing plan designed to provide
a balance between maximizing the net operating revenues from the Montana
portfolio and stabilizing these revenues. Our affiliate, PPL EnergyPlus, is
responsible for implementing our marketing plan and marketing all of the energy
that we generate. We and PPL EnergyPlus have entered into a brokering and
contract management agreement for the wholesale marketing of our energy and a
memorandum of understanding for supplying PPL EnergyPlus' retail energy
requirements. To provide diversity and stability to our revenue stream, we,
together with PPL EnergyPlus, are targeting customers throughout Montana and the
Western Systems Coordinating Council and creating a portfolio of wholesale and
retail term contracts and sales on the open market for immediately available
energy.
Through June 2002, we expect to sell approximately 60% of the energy that
we generate to MPC under two energy purchase agreements entered into in
connection with our acquisition of the Montana portfolio. These energy purchase
agreements should provide us with a revenue base as our energy marketing plan is
implemented and are expected to contribute approximately 25% of our revenues
over the remaining terms of the agreements.
Our primary market is in Montana. In this market PPL EnergyPlus arranges
for us to enter into bilateral contracts with wholesale market participants and
PPL EnergyPlus itself enters into retail contracts. We will supply the energy to
satisfy PPL EnergyPlus' obligations under the retail contracts. We cannot enter
into retail contracts directly because we are an "exempt wholesale generator"
under the Energy Policy Act.
Customers in Montana include municipalities, retail aggregators, energy
marketers and industrial and commercial users, many of whom were previously
supplied by MPC.
We expect that customers outside Montana will be predominantly utilities
and energy marketers that will purchase energy under bilateral contracts. We
also sell energy at market prices in the California power exchange.
The current transmission infrastructure of, and regional coordination
within, the Western Systems Coordinating Council enables us to transmit energy
throughout the Western Systems Coordinating Council either by Federal Energy
Regulatory Commission mandated open-access tariffs or under transmission
agreements. We expect to maintain the existing interconnections to the MPC
transmission grid, subject to an interconnection agreement with MPC.
We currently intend to enter into new contracts of varying length.
Following the expiration of our energy purchase agreements with MPC, we
currently plan to sell approximately 50% of our output under long-term contracts
of 2 years or longer. We expect short-term contracts of 1 month to 2 years will
represent approximately 40% of our portfolio with the remaining output sold in
the market for immediately available energy.
In addition to energy we produce from our generating facilities, we make
seasonal purchases of energy through an energy purchase contract with Basin
Electric Power Cooperative and PPL EnergyPlus arranges open market purchases of
energy on our behalf. These energy purchases are primarily made to satisfy
supply obligations to our customers. To the extent these purchases are not
offset by supply obligations, they are subject to our risk management program.
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Risk management program
We have developed a risk management program, which has been approved by our
board of managers and is consistent with corporate risk objectives, in order to
quantify, manage and hedge risks and exposures arising from our energy marketing
activities. The energy marketing activities of PPL EnergyPlus on our behalf
comply with PPL Corporation's financial risk management program. These programs
provide for a comprehensive framework in which to manage exposures.
Two key programs help ensure that our risk controls are consistent with
approved risk tolerances:
- the credit risk program addresses specific exposure to counterparties;
and
- the risk management program addresses the risks associated with wholesale
energy marketing and trading.
PPL EnergyPlus employs a risk manager and PPL Corporation employs a trading
controls officer. Together, their responsibilities include independent oversight
of risk policy compliance, consultation on proposed transactions, stress testing
and scenario analysis.
We have adopted and modified for our purposes the risk management policies
of PPL Corporation which relate to counterparty and exposure management. With
the exception of limited hourly purchases, under these risk management policies
we attempt to structure arrangements that match our supply obligations with our
physical and purchased energy generation capacity and limit our speculative
transaction exposure.
FUEL PROCUREMENT
The Colstrip facility is located at the mouth of the Rosebud Mine, which is
currently operated by Western Energy Company, a subsidiary of MPC. On September
15, 2000, MPC announced that it had entered into an agreement with Westmoreland
Coal Company under which Westmoreland Coal is, subject to contingencies and
regulatory approvals, to acquire MPC's coal business unit, including the
operations of Western Energy Company. The Rosebud Mine has been, and is expected
to continue to be, a stable, reliable supplier to the Colstrip facility. There
are coal reserves available at the Rosebud Mine which are adequate to satisfy
current contractual commitments to the Colstrip facility. Rosebud Mine reserves
and resources beyond those currently committed are adequate to fuel the Colstrip
facility through the term of the certificates.
The Corette facility obtains fuel from the large mines in Wyoming's
Southern Powder River Basin under short-term agreements. Currently, the Corette
facility obtains its coal from an unaffiliated company through a coal supply
contract that expires on December 31, 2001. The Southern Powder River Basin can
also serve as an alternative supply for the Colstrip facility's generating
requirements.
EMPLOYEES AND LABOR RELATIONS
We employ approximately 470 employees, including approximately 345 at the
Colstrip facility, approximately 75 at the hydroelectric facilities,
approximately 36 at the Corette facility and approximately 14 at our corporate
office in Billings, Montana. Three union locals (International Brotherhood of
Electrical Workers, Local 1638, International Brotherhood of Electrical Workers,
Local 44 and International Brotherhood of Teamsters, Local 190) represent
employees at our facilities. The current collective bargaining agreements with
IBEW Local 1638 and IBEW Local 44 both expire on April 30, 2001, and the
agreement with IBT Local 190 expires on June 30, 2001. The three union locals
collectively represent approximately 330 employees or approximately 70% of our
workforce.
We believe that we have a good relationship with our employees.
LEGAL PROCEEDINGS
We are not currently involved in any legal proceedings the outcome of which
would have a material adverse effect on our financial condition or results of
operations.
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On April 28, 2000, three employees at the Colstrip facility were severely
burned when an equipment fault in Colstrip unit 1 caused electrical arcing. The
Occupational Safety and Health Administration is conducting an investigation of
the incident. Colstrip unit 1 is operated by us and jointly owned with Puget. On
May 15, 2000, the injured employees and their spouses filed litigation for their
injuries in state district court against MPC. As of the date of this prospectus
we have not yet been named as a party defendant although the plaintiff has made
a motion to do so. The court has not yet ruled on that motion but the threat of
being made a party defendant to the pending litigation certainly exists. Having
had no direct involvement with the litigation up to this point, it is too early
to predict the likelihood of plaintiffs establishing any liability on our part
for the injuries of the plaintiffs or to realistically estimate the scope of any
potential damages award against the ultimate defendants.
MPC REORGANIZATION AND DISPOSITIONS
On March 28, 2000, MPC announced its decision to divest its energy
businesses, including its energy and natural gas delivery utilities, to focus
solely on its fiber-optic and wireless telecommunications networks, which it
operates under the name Touch America. Having previously announced the sales of
its oil and gas properties on August 28, its coal business unit on September 15
and its independent power business on September 20, MPC announced on October 2,
2000 that it had entered into an agreement with Northwestern Corporation under
which Northwestern is, subject to contingencies and regulatory approvals, to
acquire MPC's electric and natural gas transmission and distribution assets.
We do not expect MPC's decision to divest its energy businesses to have a
material effect on the operation of our generating facilities or on our
business. MPC's electric business will become a new subsidiary of Northwestern,
and this subsidiary will retain all of MPC's obligations to us, so our
contractual relationships will remain unchanged. MPC has further stated that it
will seek necessary consents from other owners of interests in the Colstrip
station in order to complete the transaction, so that the replacement of MPC by
the new Northwestern subsidiary will not conflict with our Colstrip
arrangements.
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REGULATION
ENERGY REGULATORY MATTERS
General
Our ownership and operation of the Montana portfolio are subject to
numerous federal, state and local statutes and regulations. These statutes and
regulations, among other things, govern to a certain extent the rates that we
may charge for the output of the Montana portfolio and establish, in certain
instances, the operating standards for the Montana portfolio.
Federal regulation
Federal Power Act. Under the Federal Power Act, the Federal Energy
Regulatory Commission possesses exclusive rate-making jurisdiction over
wholesale sales of energy and transmission in interstate commerce. The Federal
Energy Regulatory Commission regulates the owners of facilities used for the
wholesale sale of energy and transmission in interstate commerce as "public
utilities" under the Federal Power Act.
Under Section 203 of the Federal Power Act, MPC was required to obtain
Federal Energy Regulatory Commission approval to sell jurisdictional facilities.
On June 22, 1999, the Federal Energy Regulatory Commission approved the sale of
the jurisdictional facilities to us.
All public utilities subject to the Federal Energy Regulatory Commission's
jurisdiction are required to obtain the Federal Energy Regulatory Commission's
acceptance of their rate schedules in connection with the wholesale sale of
energy. On August 24, 1999, the Federal Energy Regulatory Commission authorized
us to make wholesale sales of energy at market-based rates, subject to various
standard regulatory conditions, to willing purchasers in wholesale markets. On
June 22 and June 29, 1999, the Federal Energy Regulatory Commission accepted for
filing our proposed sales of energy to MPC pursuant to the energy purchase
agreements with MPC.
On August 24, 1999, the Federal Energy Regulatory Commission ruled that to
the extent we acquire portions of the Colstrip transmission system, we must have
on file with the Federal Energy Regulatory Commission an open-access tariff
permitting our competitors to use available capacity in our transmission
facilities on a non-discriminatory basis at regulated rates. On November 2,
1999, we filed with the Federal Energy Regulatory Commission an open-access
tariff to be applicable for transmission services rendered over the Colstrip
transmission system in which we were potentially acquiring interests from MPC.
By a letter-order issued on December 29, 1999, the Federal Energy Regulatory
Commission accepted the tariff for filing, with an effective date of December
16, 1999. In the event that we acquire an interest in the Colstrip transmission
system from MPC, the Federal Energy Regulatory Commission may require us to
revise the rates for transmission services over the Colstrip transmission
system.
Under these open-access tariffs, parties not presently involved in the
Colstrip facility can reserve access on the Colstrip transmission system if
available. Under certain conditions, this could result in transmission
constraints to us or the need to upgrade the Colstrip transmission system. As a
result, we and the other existing users of the Colstrip transmission system may
be required to bear some portion of the costs to upgrade the Colstrip
transmission system. We cannot assure you that this situation will not arise in
the future. The open-access tariffs on the Colstrip transmission system are
equally available to us, PPL EnergyPlus and our customers to transport energy to
market.
In addition, under the Federal Power Act, transmission owners are able to
modify existing tariffs or file new tariffs from time to time. Thus, we cannot
assure you that the terms and conditions of these third party open-access
tariffs will not change in the future. The Federal Power Act provides procedural
rights to transmission customers in the event of disputes over tariffs and
open-access, but we cannot assure you that any dispute would be resolved in
favor of the interests represented by the certificates.
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On September 22, 1999, the Federal Energy Regulatory Commission authorized
us to enter into sale and leaseback transactions of our interests in the
Colstrip facility for financing purposes.
All of the hydroelectric generating facilities are licensed by the Federal
Energy Regulatory Commission. These licenses expire periodically and the
generating facilities must be relicensed at that time. The Federal Energy
Regulatory Commission license for the Mystic facility expires in 2009; the
Thompson Falls and Kerr Federal Energy Regulatory Commission licenses expire in
2025 and 2035, respectively and the Missouri-Madison facilities' license expires
in 2040. A Federal Energy Regulatory Commission relicensing proceeding gives the
current owner (and other interested parties) an opportunity to obtain a new or
renewed license for the generating facilities. Such proceedings can impose
additional conditions on the generating facilities that were not included in the
original license and cannot always be anticipated. In a recent policy statement,
the Federal Energy Regulatory Commission also has asserted that it can deny
relicensing and otherwise require decommissioning of existing generating
facilities, although this jurisdiction has only been exercised in very limited
circumstances to date. Thus, there can be no assurance that, upon or subsequent
to relicensing of any of our hydroelectric generating facilities, additional
conditions or relicensing obligations will not adversely affect our ability to
make payments under the leases.
In addition, transfers of existing licenses must be approved by the Federal
Energy Regulatory Commission under Section 8 of the Federal Power Act. The
Federal Energy Regulatory Commission approved the transfer of the MPC
hydroelectric licenses on July 7, 1999. On October 27, 1999, the Federal Energy
Regulatory Commission approved administrative license amendments to conform the
transferred licenses to the asset purchase agreement.
In 1994, the Federal Energy Regulatory Commission adopted a policy
statement in which it asserted that it has authority over the decommissioning of
licensed hydroelectric generating facilities being abandoned or denied a new
license. However, in the process leading to the policy statement, the Federal
Energy Regulatory Commission recognized that mandated generating facility
removal would occur in only rare circumstances. The only such decommissioning to
date occurred in June 1999, in Maine. The Federal Energy Regulatory Commission
also declined to require any generic funding mechanism to cover decommissioning
costs. If a generating facility is decommissioned, then the licensee may incur
substantial costs.
Public Utility Holding Company Act. The Public Utility Holding Company
Act, or PUHCA, provides that any corporation, partnership or other entity or
organized group that owns, controls or holds power to vote 10% or more of the
outstanding voting securities of a "public utility company" or a company that is
a "holding company" of a public utility company is subject to regulation under
PUHCA, unless an exemption is established or an order is issued by the SEC
declaring it not to be a holding company. Registered holding companies under
PUHCA are required to limit their utility operations to a single integrated
utility system and to divest any other operations not functionally related to
the operation of the utility system. In addition, a public utility company that
is a subsidiary of a registered holding company under PUHCA is subject to
financial and organizational regulation, including approval by the SEC of
certain of its financing transactions. PPL Corporation is a holding company
exempt from registration under PUHCA. As a result, neither PPL Corporation nor
its subsidiaries including ourselves have been required to obtain SEC approval
prior to acquiring the Montana portfolio or entering into the lease
transactions.
Under the Energy Policy Act, a company engaged exclusively in the business
of owning and/or operating a facility used for the generation of energy for sale
at wholesale may be exempted from PUHCA regulation as an "exempt wholesale
generator." On September 24, 1999, we received exempt wholesale generator status
from the Federal Energy Regulatory Commission for our generating and associated
facilities acquired from MPC. As exempt wholesale generators, we and the owner
lessors are precluded from making any direct sales to retail customers, or we
risk losing our exempt status and becoming "electric utility companies" as that
term is defined in PUHCA. In addition, any such retail sales and the retail
seller may be subject to state utility jurisdiction. Thus any sales to retail
customers in Montana or elsewhere will be effectuated via a wholesale sale from
us to PPL EnergyPlus or another wholesale purchaser, which may then make retail
sales in accordance with the state law in the relevant jurisdictions. In that
circumstance, PPL EnergyPlus or the wholesale purchaser may become subject to
state regulation with regard to such retail sales.
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Lease transactions filings and approvals. As conditions to the
consummation of the lease transactions, we and the appropriate financial
participants in the lease transactions are required to obtain certain approvals
from the Federal Energy Regulatory Commission. We and the owner lessors have
obtained all approvals necessary for the lease transactions. The Federal Energy
Regulatory Commission has approved the sale and leaseback of Federal Energy
Regulatory Commission-jurisdictional facilities pursuant to the lease
transactions. The Federal Energy Regulatory Commission has granted a disclaimer
of jurisdiction over each of the owner investors and the owner lessors (and the
trustees thereunder) as public utilities under Parts II or III of the Federal
Power Act. The owner lessors have received determinations from the Federal
Energy Regulatory Commission that they are exempt wholesale generators, which
exempt them from regulation under PUHCA.
In the event that the indenture trustees exercise certain remedies under
their respective indentures and the collateral becomes the property of the pass
through trust, additional federal and state approvals may be required from the
SEC, the Federal Energy Regulatory Commission or the State of Montana (and other
state or federal agencies with respect to permits and other like entitlements)
before the exercise of such remedies may be consummated. The likelihood of
obtaining such approvals, or any associated terms and conditions, will depend on
the law then in effect and on the particular facts and circumstances presented
by such proposed transfer.
State regulation
As an exempt wholesale generator, we are exempt from regulation by the
Montana Public Service Commission with respect to energy matters.
ENVIRONMENTAL REGULATORY MATTERS
General
As is typical for generating facilities, the Montana portfolio is subject
to and required to comply with federal, state and local environmental
regulations relating to the safety and health of personnel, the public and the
environment, including the identification, generation, storage, handling,
transportation, disposal, recordkeeping, labeling, reporting of and emergency
response in connection with hazardous and toxic materials associated with the
Montana portfolio, limits on noise emissions from the Montana portfolio, safety
and health standards, practices and procedures applicable to the operation of
the Montana portfolio, and environmental protection requirements, including
standards and limitations relating to the discharge of air and water pollutants,
and protection of endangered and threatened species. Failure to comply with any
such statutes or regulations could have material adverse effects on us,
including the imposition of criminal or civil liability by regulatory agencies
or civil fines and liability to private parties, and the required expenditure of
funds to bring the Montana portfolio into compliance. In addition, pursuant to
our asset purchase agreement with MPC, we will indemnify MPC against certain
consequences of its handling, storage or emission of hazardous and toxic
materials on the sites of the assets comprising the Montana portfolio.
In 1999, the Environmental Protection Agency initiated enforcement actions
against eight utilities, asserting that older, coal-fired generating facilities
operated by those utilities have, over the years, been modified in ways that
subject them to more stringent "New Source" requirements under the Clean Air
Act. The Environmental Protection Agency recently issued notices of violation to
two additional utilities. The Environmental Protection Agency's regional office
that regulates our generating facilities has indicated an intention to issue
information requests to all utilities in its jurisdiction as well as facilities
in other industries and has issued such a request to us related to the Corette
facility. Compliance with any such Environmental Protection Agency enforcement
action could result in additional capital and operating expenses in amounts
which are not determinable at this time, but which could be significant.
The Environmental Protection Agency is also proposing to revise its
regulations in a way that will require power plants to meet "New Source"
performance standards and/or undergo "New Source" review for many maintenance
and repair activities that are currently exempted. Until the revised regulations
have been issued, we cannot estimate the additional costs they might impose upon
us. In the meantime, we will monitor this and
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other potential regulatory developments that may impact our operations and will
participate in any rulemakings applicable to our operations.
It is likely that the stringency of environmental regulations affecting us
and our operations will increase in the future. The Environmental Protection
Agency has proposed changes to its regulations so as to require power plants to
meet "New Source" performance standards and/or undergo "New Source" review for
many maintenance and repair activities that are currently exempted. The effect
of these regulations when finalized could be significant. In the meantime, we
will monitor this and other potential regulatory developments that may impact
our operations and will participate in any rulemakings applicable to our
operations.
In October 1999, the Montana Supreme Court held in favor of several
citizens' groups that the right to a clean and healthful environment is a
fundamental right guaranteed by the Montana Constitution. The court's ruling
could result in significantly more stringent environmental laws and regulations
as well as an increase in citizens' suits under Montana's environmental laws.
The effect on us of any such changes in laws or regulations or any such increase
in citizen suits is not currently determinable but could be significant.
Air emissions
The Clean Air Act and many state laws require significant reductions in
utility SO(2) and NO(x) emissions that result from burning fossil fuels in order
to reduce acid rain and ground-level ozone (smog). The major permit regulating
the Colstrip facility's air emissions is the Title V Operating Permit. The
permit for Colstrip units 1 and 2 was issued September 23, 1997 and became
effective January 1, 1998. The permit for Colstrip units 3 and 4 was issued
November 10, 1998 and became effective January 1, 1999. The permits contain
specific emission limits and monitoring requirements as well as other conditions
that must be complied with during the operation of the plant.
The Colstrip facility is currently in compliance on air quality matters. It
is not presently operating under any consent orders resulting from notices of
violations.
Sulfur dioxide (SO(2)). SO(2) emissions are regulated under New Source
Performance Standards and Title IV of the Clean Air Act. Title IV of the Clean
Air Act establishes the national Acid Rain Program to address emissions of acid
rain precursors, SO(2) and NO(x). This program mandates substantial reductions
in SO(2) emissions to meet a national cap beginning in 1995 for some facilities
and 2000 for others (Phase I and II, respectively), which can be achieved
through methods such as emission controls, allowance purchases, fuel switching
and unit retirements. The Colstrip facility is subject to Phase II of this
program, under which the facility may not emit SO(2) in quantities that exceed
the number of SO(2) allowances the Colstrip facility holds (one allowance equals
one ton of SO(2)). Allowances may be banked or sold under this program, such
that the Colstrip facility could acquire additional SO(2) allowances it needs to
operate or sell excess allowances to third parties. On the closing of the
acquisition, MPC transferred to us 5,795 tons per year of allowances through
2025 for the Colstrip facility.
The Colstrip facility meets Phase II requirements for SO(2). The Phase II
allowance allocation is premised on an emissions rate of approximately 1.2
pounds per million Btu (lbs/MMBtu). Low-sulfur coal and the modern scrubber
technology employed at the Colstrip facility have kept the SO(2) emissions
levels at Colstrip units 1 and 2 below 0.5 lbs/MMBtu and the SO(2) emissions
levels at Colstrip units 3 and 4 below 0.1 lbs/MMBtu. Thus, the number of
allowances transferred by MPC should be sufficient to cover the expected
operation of the Colstrip facility. If necessary, the scrubbers at the Colstrip
facility can be operated at a higher level of control to further reduce SO(2)
emissions, allowing a certain measure of flexibility in the operation of the
Colstrip facility.
Nitrogen oxides (NO(x)). The national Acid Rain Program also mandates
NO(x) emissions reductions from certain coal-fired energy utility boilers,
including those operated by the Colstrip facility. The Colstrip facility
complies with the Phase I standards for NO(x) emissions (0.45 lbs/MMBtu) and was
able to exercise an option to defer compliance with the Phase II standard (0.40
lbs/MMBtu) until 2009 based on early adoption of the Phase I requirements. We do
not anticipate significant capital expenditures in 2009 to comply
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with the Phase II standard given that all the Colstrip units have already
achieved NO(x) levels under 0.40 lbs/ MMBtu.
Particulates and visibility. We are involved in ambient monitoring at
three sites in proximity to the Colstrip facility and we operate three Northern
Cheyenne Indian Reservation monitoring sites. These sites monitor SO(2), NO(x)
and a variety of meteorological parameters, as well as visibility on the
reservation. We are financially obligated to support the monitoring program on
the reservation. The sites are operated by the Northern Cheyenne. We provide
quality control and technical assistance to the Northern Cheyenne, and pay a
$75,000 fee and fund a $25,000 grant per year to support the monitoring efforts
of the Northern Cheyenne. No significant problems have been identified with the
ambient monitoring program.
In July 1997, the Environmental Protection Agency issued revised and more
stringent air quality standards for ozone and coarse particulates as well as a
new standard for fine particulates. These standards were challenged and remanded
to the Environmental Protection Agency by the D.C. Circuit Court in 1999. If
finalized, these new standards could result in further reductions in NO(x) and
SO(2) being required at Colstrip. Further reduction in NO(x) and SO(2) emissions
could also be required as a result of the Environmental Protection Agency's new
regional haze rules. Currently, given the uncertain status of these
requirements, we cannot determine if they are material.
Mercury. Under the Clean Air Act, the Environmental Protection Agency has
been studying the health effects of hazardous air emissions from power plants
and other sources, in order to determine what emissions should be regulated. The
Environmental Protection Agency has concluded that mercury is the power plant
air toxin of greatest concern and the Environmental Protection Agency must
determine by the end of this year whether it must be regulated. The
Environmental Protection Agency has obtained mercury and chlorine sampling and
other data from electric generating facilities, including the Colstrip facility,
in order to make this determination. Should the Environmental Protection Agency
decide to regulate mercury, the costs to the Colstrip facility could be
substantial, depending upon the specific regulatory requirements.
Carbon dioxide (CO(2)). Environmental concerns related to the impacts of
greenhouse gases such as CO(2) led to the adoption in 1992 of the United
Nations-sponsored Framework Convention, which was ratified by over 150
countries, including the United States. In 1993, President Clinton committed the
United States to limit CO(2) and other climate-altering gas emissions to their
1990 levels by the year 2000. However, it became apparent that this goal was
unlikely to be met by most industrialized nations. The Kyoto Conference was
called in December 1997 to expedite a global climate treaty supported by the
United States. If adopted by the participating nations, any legally binding
global climate treaty will have significant economic consequences for all United
States industries, including the utility industry as a whole, and particularly
for coal-fired generating facilities. Although the United States has signed the
Kyoto Protocol which calls for significant reductions in greenhouse gas
emissions and global warming, thereby committing the United States to
significant reductions in greenhouse gas emissions between 2008 and 2012, the
United States Senate must ratify the agreement for the protocol to take effect.
Hazardous material and wastes
The energy utility industry typically utilizes or generates in its
operations a range of potentially hazardous products and by-products. We have
identified a number of site remediation issues at the Montana portfolio. Under
the terms of the asset purchase agreement, MPC has agreed to indemnify us for
certain losses relating to pre-existing on-site environmental conditions,
subject to the limitation that its obligation to indemnify us for losses
associated with the cost of remediating pre-existing on-site environmental
conditions is limited to 50% of its pro-rata share of such environmental
liability not to exceed in the aggregate 10% of the purchase price of the
Montana portfolio.
Coal combustion wastes are regulated under the Resource Conservation and
Recovery Act, or RCRA, which governs the handling, treatment and disposal of
hazardous and non-hazardous wastes. Under the so-called Bevill Amendment to RCRA
in 1980, wastes from coal-burning generating facilities were temporarily
classified as non-hazardous for purposes of regulation, which meant that these
wastes would be exempt from the significantly more stringent (and costly)
regulatory requirements for hazardous wastes. The Environmen-
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tal Protection Agency, however, was directed by statute to determine whether
these wastes should be regulated as hazardous wastes. The Environmental
Protection Agency recently concluded that coal combustion wastes should be
regulated as non-hazardous wastes, but indicated that it may revisit this issue
if public health risks are identified or if states (which manage the handling
and disposal of solid waste) do not take steps to address these wastes
adequately in a reasonable amount of time. Consequently, it is possible that the
Environmental Protection Agency could seek to regulate coal combustion wastes as
hazardous wastes in the future. Any such regulations could have a significant
cost impact on the Colstrip facility.
Environmental site assessments
MPC prepared a Phase I Environmental Site Assessment for the Montana
portfolio. The Phase I Environmental Site Assessment reports, dated May 1998,
consisted of site reconnaissance, interviews, review of facility files, and
review of relevant government agency files. MPC subsequently engaged a
consultant to perform Phase II environmental investigations at its facilities in
August 1998. MPC's consultant updated the remedial cost estimates presented in
October 1999 and we further revised these estimates in May 2000. The Phase II
investigations consisted of (1) site reconnaissance of the facilities, (2)
supplemental interviews with MPC and regulatory personnel, (3) additional
research and data review regarding various issues, and (4) sampling of soil and
groundwater at various portions of the sites for the plants.
The American Society for Testing and Materials has developed standards for
conducting Phase I assessments. As a general matter, these standards do not
recommend relying on such reports to the extent they are more than 180 days old.
We have not conducted any independent investigation of environmental conditions
at the sites of the Montana portfolio, but have relied exclusively on the 1998
Phase I Environmental Site Assessments and related October 1999 Phase II
reports. Except as otherwise discussed in this prospectus, we are not aware of
any other environmental conditions at the Colstrip facility (or in the aggregate
at the other sites of the Montana portfolio) that may have a material adverse
effect on the leased assets or our ability to pay the rent. However, there can
be no assurance that such conditions do not exist, and a decision to proceed
without further environmental investigation increases the risk of such unknown
conditions to some extent.
Colstrip facility. For the Colstrip facility, MPC's Phase I Environmental
Site Assessment consisted of a site reconnaissance, review of plant files, and
interviews with plant personnel and Montana Department of Environmental Quality
representatives. According to MPC, the Colstrip facility site was mostly
undeveloped prior to initial construction in 1972. Portions of the site had
previously been mined for coal or historically used as a landfill, which is now
closed. The Phase I Environmental Site Assessment identified a complex system of
ponds used for the discharge of plant effluents and coal ash. According to MPC,
seepage from the ponds have resulted in impacts to groundwater over various
portions of the Colstrip facility site. MPC installed groundwater capture
systems to mitigate the environmental impacts. MPC's consultant identified
several areas where additional investigations and groundwater capture systems
will be required to maintain compliance with its certificate of environmental
compatibility and public need. In addition, MPC identified other historically
significant spills primarily consisting of releases of petroleum products and
other miscellaneous areas of concern. The Phase II investigations consisted of
limited soil sampling, collection of numerous groundwater samples from existing
wells and selective analysis for organic and inorganic constituents. We estimate
that our share of the "Most Probable" case scenario for mitigation of the above
issues will be approximately $3.8 million in 2000 dollars primarily for capital
expenditures spread over a period between 2000 and 2020. Most of these costs are
attributable to issues associated with groundwater impacted by the Colstrip
facility's system of effluent and ash disposal ponds. These pond-associated
costs would cover additional groundwater investigations, pond closures and
construction, dam repair, installation of groundwater capture systems, and
long-term groundwater monitoring projects.
The remaining areas of mitigation included issues associated with coal pile
leachate management, excavation and disposal of lead-contaminated soil at an
on-site shooting range, and various other petroleum products spills and
potential groundwater contamination issues. We have additionally evaluated a
cost estimate for a single large cost item that would expand the potential range
of mitigation costs at the Colstrip facility. In the event that planned
groundwater capture mitigation measures described above are ineffective, a
synthetic liner would additionally be required for a portion of the Colstrip
units 3 and 4 effluent holding pond.
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MPC's consultant considered this to be a "Low Probability" case scenario. Should
a liner installation be required, we estimate that our share of the cost to be
approximately $2 million in 2000 dollars, spread between 2010 to 2014.
Since acquiring the leased assets and becoming the operator, we have
received three violation letters from the Montana Department of Environmental
Quality. The Department of Environmental Quality issued a January 27, 2000
letter regarding a September 1999 transformer cooling oil spill that occurred
while MPC still operated Colstrip units 1 and 2. We estimate that the cost of
remediation of this issue will not be material.
On February 29, 2000, the Department of Environmental Quality issued a
violation letter regarding seepage below a saddle dam at the Colstrip units 3
and 4 holding pond. The letter required that we submit reports on May 31 and
July 31, 2000. We have submitted both reports. The letter also required us to
complete any required repairs by December 31, 2000. We have met with the
Department of Environmental Quality to discuss our plans for repair and have
reached agreement that due to the scope of repairs, as well as adequate
temporary mitigation measures currently in place, the repair of the saddle dam
can extend into the year 2003 if necessary. These repairs will also address
potential settlement concerns at the south end of the saddle dam. We estimate
that our share of the costs for repair of the saddle dam could range from
$75,000 to $2.25 million.
On March 8, 2000, the Department of Environmental Quality issued a letter
regarding a fly ash effluent return water spill at one of the Colstrip units 3
and 4 effluent drain ponds. We have resolved this matter with the Department of
Environmental Quality, and we estimate the costs related to the identified
conditions will not be material.
On March 29, 2000, a spill occurred of clear flush water being pumped by a
pipeline from the Colstrip units 1 and 2 fly ash pond to the evaporation pond.
We promptly reported the spill to the Department of Environmental Quality and
undertook corrective and remedial measures. The Department of Environmental
Quality issued a $3,700 fine, which we paid on September 15, 2000 and this
matter is resolved.
Corette facility. The Corette facility site was undeveloped farmland prior
to initial development of the site in 1950, which consisted of construction of
the Frank Bird plant which was shut down in 1984, and dismantled in 1997. The
Corette facility became operational in 1968. Since then there have been minor
spills and releases of oil and other potentially contaminated areas resulting
from historical generating facility operations.
MPC's consultant provided cost estimates to address certain other issues
including mitigation of a former on-site flyash landfill, management of coal
pile leachate, and additional investigations regarding the presence of
tetrachlorethene in the form of PCE, a chlorinated industrial solvent, found in
the groundwater during its sampling investigations. We estimate that our share
of the "Most Probable" case scenario cost for mitigation of the above issues
will be approximately $0.7 million in 2000 dollars primarily for capital
expenditures, spread over the period between 2000 and 2020.
Hydroelectric generating facilities. In general, dam construction for most
of the hydroelectric generating facilities occurred between 1906 and 1958. Some
existing dams have replaced dams constructed in the early 20th century. The
investigations of MPC's consultant encountered no evidence of buildings or
industrial activities prior to construction of the hydroelectric generating
facilities. In addition to the facilities directly related to hydroelectric
generation, some of the sites had former "employee camps" associated with
residential activity and recreational facilities. The following issues were
common at several of the hydroelectric generating facilities sites:
- use of various chemicals and hazardous substances and generation of used
oil and small amounts of hazardous waste were recognized by the
investigations;
- former or current use of underground storage tanks were identified at
several sites. Only one site had currently active underground storage
tanks;
- spills of petroleum products or other release incidents. According to
MPC's consultant, none of these incidents resulted in citations or
involve any ongoing assessment, remediation, or unresolved regulatory
issues;
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- potential for PCB-containing equipment and potential spill/leak issues;
- septic systems and leachfields;
- former household trash disposal areas;
- known or suspected asbestos-containing materials exist at the plants
within floor tiles, ceiling tiles, transite materials, brake shoes, and
insulation;
- lead-based paint was identified as likely to exist at the facilities;
- the potential for elevated metals in reservoir sediments due to historic
mining operations; and
- listing of the bull trout and west slope cutthroat trout as threatened
species under the Endangered Species Act.
MPC's consultant concluded that some of these issues potentially require
mitigation at some of the hydroelectric generating facilities sites. According
to the combined estimates developed by MPC's consultant and by us, our share of
the total future costs associated with former household trash dumps at several
of the sites, a sanitary wastewater lagoon at one site, and other miscellaneous
contamination issues is approximately $0.6 million in 2000 dollars primarily for
capital expenditures, spread over a period of 2000 to 2020.
Water issues
The federal Clean Water Act prohibits the discharge of any pollutant
(including heat), except in compliance with a discharge permit issued by the
states or the Environmental Protection Agency for a term of no more than five
years. The Environmental Protection Agency has proposed requirements that could
require cooling towers at plants that are new or modified as specified in the
proposed regulations. These regulations are expected to be finalized by August
of this year. Depending on the final wording, these regulations are unlikely to
affect the Colstrip facility unless the intake structure at the plant is
modified. Another rule, expected later this year, will address existing
structures.
The Montana portfolio and its ash disposal sites have been designed and are
operated to comply with strict water and wastewater compliance standards.
Groundwater protection measures include coal pile liners at all stations other
than Colstrip, lined active ash disposal sites, no active fly ash settling
ponds, and a network of approximately 600 groundwater monitoring wells. Montana
has technology-based effluent limitations for surface water discharges and
restrictive limits on wastewater discharges to ensure that very protective water
quality-based standards are maintained. The Montana portfolio has numerous
wastewater treatment facilities in order to ensure compliance with these
restrictive discharge limits.
WATER RIGHTS
MPC transferred all water rights necessary for the operation of the Montana
portfolio to us. Water use in Montana is governed by the prior appropriation
doctrine. We believe that the water rights associated with our hydroelectric
generating facilities are sufficiently "senior" water rights to allow us to
continue to operate these facilities. Although in a very lengthy process the
Montana Water Court is currently adjudicating most water rights in Montana with
a priority date before July 1, 1973, we have no reason to believe that our filed
claims would be altered by that process in any way that would materially affect
operation of our generating facilities.
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MANAGEMENT
PPL Montana Holdings, an indirect wholly owned subsidiary of PPL
Corporation, controls us as our sole member. PPL Montana Holdings appoints our
board of managers and officers, and it may elect to appoint additional managers,
or remove current managers, from time to time at its discretion. Neither
officers nor members of the board of managers serve for a fixed term. Each
member of the board of managers holds office until his successor is elected and
qualified or until his earlier resignation or removal, and each of our officers
serves at the discretion of the board of managers. The board of managers has the
full power available to a board of managers under the law to control us.
OUR BOARD OF MANAGERS AND OFFICERS
The following table sets forth information concerning our board of managers
and officers as of the date of this prospectus.
NAME AGE POSITION
- ---- --- ------------------------------------------
Roger L. Petersen......................... 49 President, Chief Executive Officer and
Member of the Board of Managers
Michael C. Enterline(1)................... 51 Vice President and Chief Operating Officer
Paul A. Farr.............................. 33 Vice President, Chief Financial Officer
and Assistant Secretary
David B. Kinnard.......................... 49 Vice President, General Counsel and
Secretary
John R. Biggar............................ 55 Member of the Board of Managers
Paul T. Champagne......................... 42 Member of the Board of Managers
Robert J. Grey............................ 49 Member of the Board of Managers
William F. Hecht.......................... 57 Member of the Board of Managers
Frank A. Long............................. 59 Member of the Board of Managers
- ---------------
(1) Effective January 12, 2001, Mr. Enterline resigned as Vice President and
Chief Operating Officer.
Roger L. Petersen has been President and CEO of PPL Montana and a member of
our board of managers since January 1999. Mr. Petersen was chief operating
officer of PPL Global from 1996 until June 1999. Mr. Petersen has been involved,
for more than 20 years, in energy facility operations, including asset
management for operating plants, business development, financing, project
management and environmental compliance in both the domestic and international
arenas. Prior to his employment with PPL Global, Mr. Petersen was employed by
Edison Mission Energy (formerly Mission Energy Company) as Regional Vice
President -- North American Operation from 1986 to 1996. Mr. Petersen holds a
bachelor's degree in mechanical engineering from South Dakota State University,
a masters in engineering from California Polytechnical Institute and a business
management degree from the University of California at Los Angeles.
Michael C. Enterline became Vice President and COO of PPL Montana in
December 1999. Mr. Enterline joined MPC in 1979 as a Shift Supervisor after
working for Puget Sound Power and Light Company at Colstrip, Montana. His career
with MPC also included the positions of Production Engineer, Superintendent of
Common Facilities, Superintendent of Colstrip units 1 and 2, Manager of Business
and Change Management, General Manager of Colstrip Operations, and in August
1995 he was promoted to Vice President, Colstrip Project Division. Mr. Enterline
became an officer of ours on December 18, 1999. Mr. Enterline earned a B.A. in
chemistry, with a minor in mathematics, in 1971 from the University of Northern
Colorado, Greeley. Effective January 12, 2001, Mr. Enterline resigned as Vice
President and Chief Operating Officer.
Paul A. Farr has been Vice President, CFO and Assistant Secretary of PPL
Montana since June 1999. Mr. Farr was the former Director of International Tax
for PPL Global and has 7 years of industry experience in the acquisition,
financing and structuring of merchant generating facilities. Before joining PPL
Global in June 1998, Mr. Farr worked at the St. Louis, Missouri office of Price
Waterhouse for two years and at the Milwaukee, Wisconsin and London, England
offices of Arthur Andersen & Co. for four years in a financial
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consultant capacity. Mr. Farr has a Bachelor of Science degree in accounting
from Marquette University and a Masters of Science in Management degree from the
Krannert School at Purdue University.
David B. Kinnard has been Vice President, General Counsel and Secretary of
PPL Montana since July 1999. Mr. Kinnard is a graduate of Montana State
University and the University of Montana School of Law. Mr. Kinnard commenced
private law practice in Billings, Montana in 1977. From 1988 through 1997, Mr.
Kinnard was General Counsel for United Tote Company, a Montana-based provider of
computerized wagering equipment and services to the legalized racing and gaming
industries. During his tenure there he also was responsible for regulatory
compliance and corporate relations, and during his last 15 months served as its
chief operating officer. He returned to private practice in February 1998 and
joined us in July 1999.
John R. Biggar, Senior Vice President and CFO of PPL Corporation as well as
its subsidiary, PPL Electric Utilities. Before being named to his current
position in 1998, Mr. Biggar served 14 years as Vice President -- Finance of PPL
Corporation. He started his career in 1969 as an attorney in the legal
department of PPL Corporation, was promoted to corporate attorney three years
later and, in 1975, became Manager -- Financing Services. Mr. Biggar also served
as Manager -- Finance and as an assistant treasurer of PPL Corporation. Mr.
Biggar is a graduate of the College of Law at Syracuse University and has a
bachelor's degree in political science from Lycoming College. Mr. Biggar has
been a member of our board of managers since June 1999.
Paul T. Champagne, President of PPL Global. Mr. Champagne joined PPL
Global in 1995 as Vice President and Senior Development Officer and was promoted
to his current position in May 1999. Prior to joining PPL Global, he served for
six years in several business development roles at Edison Mission Energy
Company, including Midwest Regional Manager, where he was responsible for
acquisitions and greenfield development opportunities. Mr. Champagne earned a
bachelor's degree in chemical engineering and completed master's course work in
mechanical engineering at the University of Illinois. Mr. Champagne has been a
member of our board of managers since January 1999.
Robert J. Grey, Senior Vice President, General Counsel and Secretary of PPL
Corporation as well as its subsidiary, PPL Electric Utilities. Mr. Grey joined
PPL Corporation in 1995 as Vice President, General Counsel and Secretary and was
promoted to his current position in March, 1996. Prior to his work at PPL
Corporation, Mr. Grey was General Counsel for Long Island Lighting Co. for two
and a half years. Prior to that, he had been a partner with the law firm of
Preston Gates & Ellis. Mr. Grey's experience also includes work as a staff
counsel for the New York Public Service Commission and he served as an attorney
for the U.S. Environmental Protection Agency. Mr. Grey has a bachelor of arts
degree from Columbia University, a doctor of law degree from Emory University
and a master of law degree in taxation from George Washington University. Mr.
Grey has been a member of our board of managers since June 1999.
William F. Hecht, Chairman, President and Chief Executive Officer of PPL
Corporation. Mr. Hecht joined PPL Corporation in 1964 and worked in a number of
engineering and management positions before being named Vice President-System
Power in 1983. He has also served as Vice President -- Marketing & Economic
Development, Vice President -- Power Production & Engineering and Senior Vice
President -- System Power & Engineering. In 1990, he was named Executive Vice
President -- Operations and was elected to PPL Corporation's board of directors.
Mr. Hecht was named President in 1991 and in 1993 was also named Chairman and
Chief Executive Officer. Mr. Hecht holds bachelor's and master's degrees in
engineering from Lehigh University and is also a graduate of the Cornell
University Executive Development Program. Mr. Hecht has been a member of our
board of managers since June 1999.
Frank A. Long, Executive Vice President of PPL Corporation and Executive
Vice President and Chief Operating Officer of PPL Electric Utilities. Mr. Long
started his career with PPL Corporation in 1963 as an engineer in the system
planning department. He has served as Manager -- Engineering Systems, Manager --
Engineering & Scientific Systems, Manager -- Systems & Programming,
Manager -- System Planning and was named Vice President -- Power Supply in 1989.
In 1990 he was appointed Senior Vice President -- System Power & Engineering.
Mr. Long was named Executive Vice President and Chief Operating Officer of PPL
Electric Utilities in January 1993 and became Executive Vice President of PPL
Corporation in
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April 1995. Mr. Long has a bachelor of science degree in electrical engineering
from Northeastern University. Mr. Long has been a member of our board of
managers since June 1999.
COMPENSATION OF MANAGEMENT
All members of our management participate in employee benefit plans and
arrangements sponsored by PPL Corporation or by us, including the PPL Incentive
Compensation Plan for Key Employees, the PPL Incentive Compensation Plan, the
PPL Montana Supplemental Executive Retirement Plan, the PPL Montana Officers
Deferred Compensation Plan, health, life insurance and pension plans and other
plans which may be established in the future. We will not reimburse PPL
Corporation for management participation in any benefit plans sponsored, other
than costs related to issuances under stock option plans.
The following table summarizes all compensation for our chief executive
officer and all three of our executive officers, whom we refer to collectively
as the named executive officers, for the last fiscal year, for service for us.
We commenced operations on December 17, 1999, therefore there were no officers
who received compensation in excess of $100,000 for the period from inception to
December 31, 1999.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
------------------------------------- ------------------------------------------------
SECURITIES
OTHER ANNUAL RESTRICTED UNDERLYING ALL OTHER
NAME AND SALARY BONUS COMPENSATION(1) STOCK AWARD(S)(2) OPTIONS COMPENSATION(3)
PRINCIPAL POSITION YEAR ($) ($) ($) ($) (#) ($)
------------------ -------- -------- -------- --------------- ----------------- ---------- ---------------
Roger L. Petersen....... 2000 286,860 107,762 3,245 463,505 26,440 12,390
President and Chief
Executive Officer
Michael C. Enterline.... 2000 160,670 64,049 7,210 996 16,390 10,503
Vice President and Chief
Operating Officer(4)
Paul A. Farr............ 2000 143,020 56,916 790 20,467 14,490 10,699
Vice President, Chief
Financial Officer and
Assistant Secretary
David B. Kinnard........ 2000 155,710 62,064 8,508 10,951 15,680 9,351
Vice President, General
Counsel and Secretary
- ---------------
(1) Amount stated includes longevity pay, which is compensation for vacation
earned but not taken.
(2) As of December 31, 2000, the named executive officers held the following
number of shares of restricted common stock of PPL Corporation, with the
following values: Mr. Petersen -- 28,510 shares ($1,290,078); Mr.
Enterline -- 50 shares ($2,263); Mr. Farr -- 1,508 shares ($68,237); and Mr.
Kinnard -- 550 shares ($24,888). This year-end data does not include awards
made in January 2001 for 2000 performance, or awards which had originally
been restricted and for which the restriction periods have lapsed or been
lifted. Dividends are paid currently on restricted stock awards.
(3) Includes contributions by us to the Officers' Deferred Savings Plan account.
(4) Effective January 12, 2001, Mr. Enterline resigned as Vice President and
Chief Operating Officer.
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Option Grants in Last Fiscal Year
The following table provides information on option grants in fiscal year
2000 to the named executive officers.
INDIVIDUAL GRANTS(1)
---------------------------------------------------------------------------------------
NUMBER OF
SECURITIES
UNDERLYING
OPTIONS % OF TOTAL OPTIONS GRANT DATE(2)
GRANTED GRANTED TO PPL EXERCISE OR BASE PRESENT VALUE
NAME # EMPLOYEES IN 2000 PRICE($/SH) EXPIRATION DATE ($)
---- ---------- ------------------ ---------------- --------------- ----------------
R.L. Petersen..... 26,440 1.8 19.91 3/7/10 104,702
M.C. Enterline.... 16,390 1.1 19.91 3/7/10 64,904
P.A. Farr......... 14,490 1.0 19.91 3/7/10 57,380
D.B. Kinnard...... 15,860 1.0 19.91 3/7/10 62,806
- ---------------
(1) Exercisable in three equal annual installments beginning March 6, 2001.
(2) Values indicated are an estimate based on a modified binomial option pricing
model. Although executives risk forfeiting these options under certain
circumstances, these risks are not factored into the calculated values. The
actual value realized will be determined by the excess of the stock price
over the exercise price on the date the option is exercised. There is no
certainty that the actual value realized will be at or near the value
estimated by the modified binomial option pricing model.
Assumptions used for the modified binomial model are as follows:
Risk-free interest
Rate........................................................ 6.62%
Volatility.................................................. 21.38%
Dividend yield.............................................. 5.70%
Time of exercise............................................ 10 years
Change in Control Arrangements
We have entered into an agreement with Mr. Petersen, which provides
benefits upon termination of employment in certain circumstances following a
change in control, as defined in the agreement. The benefits provided under the
agreement replace any other severance benefits provided to Mr. Petersen by us,
or any prior severance agreement.
Mr. Petersen's agreement is effective through December 31, 2001, and
generally is automatically extended for additional one-year periods. Upon the
occurrence of a change in control, the agreement will expire no earlier than
thirty-six months after the month in which the change in control occurs. The
agreement provides the severance benefits described below if we terminate Mr.
Petersen's employment following a change in control for any reason other than
death, disability, retirement or "cause," or if Mr. Petersen terminates
employment for "good reason" (as those terms are defined in the agreement).
The benefits consist of a lump sum payment equal to three times the sum of:
(a) base salary in effect immediately prior to date of termination, or if
higher, immediately prior to the first occurrence of an event or
circumstance constituting good reason, and
(b) the highest annual bonus in respect of the last three fiscal years
ending immediately prior to the fiscal year in which the change in
control occurs, or if higher, the fiscal year immediately prior to the
fiscal year in which first occurs an event or circumstance constituting
good reason. This bonus amount would include the value of restricted
stock awards for calendar years prior to 1999.
In addition, under the terms of the agreement, we would provide Mr.
Petersen and his dependents with continuation of welfare benefits (reduced to
the extent Mr. Petersen receives comparable benefits), and would
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pay Mr. Petersen unpaid incentive compensation that has been allocated or
awarded, a lump sum payment having an actuarial present value equal to the
additional pension benefits Mr. Petersen would have received had he continued to
be employed by us for an additional thirty-six months, and outplacement services
for up to three years. In addition, under the agreement, we would provide
post-retirement health care and life insurance benefits to Mr. Petersen if he
would have become eligible for those benefits within the thirty-six month period
following the change in control.
In addition, in the event of a change in control or certain circumstances
that may lead to a change in control, the compensation and corporate governance
committee of the board of directors of PPL Corporation may change or eliminate
the restriction period applicable to any outstanding restricted stock awards
under the Incentive Compensation Plan.
Policies for Setting Executive Compensation
Our ultimate parent, PPL Corporation, has a committee of independent
members of its Board of Directors that establish the executive compensation
policy. This policy applies to PPL Corporation affiliated companies, including
us. The overall compensation objective is to provide compensation levels that
are competitive with comparable companies to enable us to attract and retain
high quality executives. To meet this objective the total compensation proposed
for our executives consists of a base salary in the 50% percentile range of
officer salaries at comparable energy and other similar businesses. Short term
cash and stock incentives are based on pre-established goals for us and PPL
Corporation. Additionally, our executives receive long term incentives in the
form of stock options. Future cash incentive awards will be targeted to specific
performance goals established by the executive compensation policy. During 2000
restricted stock and stock option grants were awarded to our executive officers,
as shown in the table on page 61 based on pre-established target levels.
RETIREMENT PLANS FOR EXECUTIVE OFFICERS
Upon retirement, our officers are eligible for benefits under the PPL
Montana Retirement Plan and the Supplemental Executive Retirement Plan.
The following table shows the estimated annual retirement benefits for
executive officers payable under these Plans:
PENSION PLAN TABLE
- -------------------------------------------------------------------------------------------
YEARS OF SERVICE
--------------------------------------------------------
REMUNERATION 15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS
------------ -------- -------- -------- -------- --------
100,000........................ 30,000 40,000 50,000 60,000 70,000
150,000........................ 45,000 60,000 75,000 90,000 105,000
200,000........................ 60,000 80,000 100,000 120,000 140,000
250,000........................ 75,000 100,000 125,000 150,000 175,000
300,000........................ 90,000 120,000 150,000 180,000 210,000
350,000........................ 105,000 140,000 175,000 210,000 245,000
400,000........................ 120,000 160,000 200,000 240,000 280,000
450,000........................ 135,000 180,000 225,000 270,000 315,000
500,000........................ 150,000 200,000 250,000 300,000 350,000
550,000........................ 165,000 220,000 275,000 330,000 385,000
600,000........................ 180,000 240,000 300,000 360,000 420,000
650,000........................ 195,000 260,000 325,000 390,000 455,000
700,000........................ 210,000 280,000 350,000 420,000 490,000
Benefits under both the Retirement Plan and the Supplemental Executive
Retirement Plan benefit formulas are based on length of service and the average
compensation for the highest 60 consecutive months
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in the final 120 months of employment. For purposes of calculating benefits
under the Retirement Plan, the compensation used is base salary less amounts
deferred pursuant to the Officers Deferred Compensation Plan. Base salary,
including any amounts deferred, is listed in the Summary Compensation Table on
page 61. (Of the officers listed in that table, Mr. Petersen deferred $180,288
of compensation for 2000.) The benefits under the Supplemental Executive
Retirement Plan are 2.0% of the base salary for each year of service.
Benefits payable under the Retirement Plan are subject to limits set forth
in the Internal Revenue Code and are not subject to any deduction for Social
Security benefits or other offset. They are computed on the basis of the life
annuity form of pension at the normal retirement age of 65. Benefits payable
under the Supplemental Executive Retirement Plan are computed on the same basis;
are offset by Retirement Plan benefits and the maximum Social Security benefit
payable at 65; and are reduced for retirement prior to age 60.
As of January 1, 2001 the years of credited service under the Supplemental
Executive Retirement Plan for Messrs. Farr and Kinnard were 1 year. Under the
terms of the plans Mr. Petersen is entitled to a minimum of 30 years of service
once he attains the age of 60.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All our executive officers as a group own 0.02% of PPL Corporation's common
stock. The following table sets forth the amount of PPL Corporation's common
stock that our executive officers owned as December 31, 2000:
SHARES OF COMMON STOCK
NAME BENEFICIALLY OWNED (1)
---- ----------------------
Roger L. Petersen........................................... 31,821
Michael C. Enterline........................................ 881
Paul A. Farr................................................ 1,517
David B. Kinnard............................................ 1,381
All executive officers as a group........................... 35,600
- ---------------
(1) The number of shares beneficially owned includes:
(a) shares directly owned by certain relatives with whom officers share
voting or investment power;
(b) shares held of record individually by a officer or jointly with others
or held in the name of a bank, broker or nominee for such individual's
account; and
(c) shares in which certain officers maintain exclusive or shared
investment or voting power, whether or not the securities are held for
their benefit.
There are no shares that the above executive officers have the right to acquire
within 60 days from December 31, 2000.
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RELATIONSHIPS AND RELATED TRANSACTIONS
We are an indirect wholly owned subsidiary of PPL Corporation. Since our
formation, PPL Corporation has indirectly provided all of our equity funding.
Our only other source of future funding in addition to permitted indebtedness
under the participation agreements, which includes indebtedness under the
working capital facility, is cash flow from the Montana portfolio. In the event
of a shortfall between the amount of our commitments and the foregoing sources
of funds, PPL Corporation is not obligated to provide any loans or equity
contributions to make up such shortfall.
PPL Corporation has the power to control us. In circumstances involving a
conflict of interest between PPL Corporation, as the sole indirect equity owner,
on the one hand, and certificate holders, effectively as our creditors, on the
other, we cannot assure you that PPL Corporation would not exercise its power to
control us in a manner that would benefit PPL Corporation to the detriment of
the certificate holders.
PPL Corporation's existing generating facilities do not currently compete
with the Montana portfolio. However, it is possible that in the future PPL
Corporation or its subsidiaries may undertake projects that could ultimately
compete with the Montana portfolio.
We have executed a brokering and contract management agreement and a
memorandum of understanding with our affiliate PPL EnergyPlus, which we describe
in more detail on page 80.
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SUMMARY OF INDEPENDENT ENGINEER'S REPORT
Our independent engineer, R.W. Beck, Inc., has prepared a report about our
generating facilities, a copy of which is set forth as Appendix A to this
prospectus. Following is a summary of the conclusions reached by the independent
engineer in its report. The independent engineer's conclusions are subject to
the assumptions and qualifications set forth in the independent engineer's
report, and you should read this summary in conjunction with the full text of
the independent engineer's report. The descriptive terms used in this summary
may differ from the terms we use elsewhere in this prospectus. Terms that are
not defined in this summary or elsewhere in this prospectus are defined in the
independent engineer's report.
The independent engineer has expressed the following opinions:
- The sites for the generating facilities included in the Montana portfolio
are suitable for the facilities' continued operation.
- The generating facilities have been designed and constructed in
accordance with good engineering practices and generally accepted
industry practices and the technologies in use at the generating
facilities are sound, proven conventional methods of electric and thermal
generation. Furthermore, all major off-site requirements for the
generating facilities are adequately provided for, including coal supply,
water supply and electrical interconnections. If operated and maintained
as they are currently, the generating facilities should be capable of
meeting the currently applicable environmental permit requirements.
- The Colstrip transmission system utilizes sound technology and proven
methods of electricity transmission and has generally been designed and
constructed in accordance with generally accepted industry practice.
- Colstrip units 1, 2, 3 and 4 and the Corette facility should be capable
of achieving annual average equivalent availability factors of 87.9%,
84.9%, 88.7%, 86.3% and 85.7%, respectively, over the term of the
certificates. There will be years when the availability is both above and
below the projected annual average.
- The generating facilities and the Colstrip transmission system should
have a useful life extending well beyond the term of the certificates.
- The dam safety inspection reports for the hydroelectric facilities were
conducted in a manner consistent with industry standards, using
comparable industry protocols for similar studies with which the
independent engineer is familiar.
- The environmental site assessments and subsurface investigations of the
sites for the generating facilities were conducted in a manner consistent
with industry standards, using comparable industry protocols for similar
studies with which the independent engineer is familiar.
- The major permits and approvals required to operate the generating
facilities have been obtained and are currently valid and the independent
engineer is not aware of any technical circumstances that would prevent
the issuance of a new Federal Energy Regulatory Commission license for
the Missouri-Madison hydroelectric generating facilities.
- By combining the demonstrated experience of the current PPL Montana
programs and operating team with the operating experience of PPL
Generation, PPL Montana should have sufficient capability to operate the
generating facilities effectively. The operating programs and procedures
which are currently in place are consistent with generally accepted
practices of the industry and, with the exception of the Colstrip
facility, the generating facilities have incorporated organizational
structures that are comparable to other facilities using similar
technologies. However, it appears that the Colstrip facility personnel
have successfully incorporated an organizational structure which is less
typical of the industry.
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- Based on the operating history, proposed operation and maintenance
practices, observed conditions and proposed capital expenditures:
(a) Each of Colstrip units 1 and 2 should be capable of delivering net
electrical capacity of 307 MW at a full load net heat rate of 11,124
Btu/kWh.
(b) Each of Colstrip units 3 and 4 should be capable of delivering net
electrical capacity of 740 MW at a full load net heat rate of 10,459
Btu/kWh.
(c) The Corette facility should be capable of delivering net electrical
capacity of 154 MW at an annual average net heat rate of 11,100
Btu/kWh.
- The methodology used by PPL Montana to estimate energy from the
hydroelectric facilities using historical streamflow records is
consistent with industry standards.
- The generating facilities appear to be operating in general compliance
with applicable environmental permits, approvals, laws, rules and
regulations.
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SUMMARY OF INDEPENDENT MARKET CONSULTANT'S REPORT
Our independent market consultant, PA Consulting Services Inc., formerly
known as PHB Hagler Bailly, Inc., has prepared a report, a copy of which is set
forth as Appendix B to this prospectus. Following is a summary of the
conclusions reached by the independent market consultant in its report. The
independent market consultant's conclusions are subject to the assumptions and
qualifications set forth in the independent market consultant's report, and you
should read this summary in conjunction with the full text of the independent
market consultant's report. The descriptive terms used in this summary may
differ from the terms we use elsewhere in this prospectus. Terms that are not
defined in this summary or elsewhere in this prospectus are defined in the
independent market consultant's report.
The predictions, estimates and forecasts included in the independent market
consultant's report are based on assumptions with respect to conditions which
may exist or events which may occur in the future. While the independent market
consultant believes these assumptions to be reasonable for purposes of preparing
this report, they are dependent upon future events that are not within our
control, the independent market consultant's control or any other person's
control. The predictions and estimates may also differ from that which other
experts specializing in the electricity industry might present. You should be
aware that actual future results may differ, perhaps materially, from those
projected. No one can give you assurance that the assumptions used will prove to
be correct or that the predictions, estimates and forecasts will match actual
results of operations. The independent market consultant does not make, nor
intends to make, nor should you infer, any representation with respect to the
likelihood of any future outcome. In addition, the report is not intended to be
a complete and exhaustive analysis, and may not consider all of the relevant
factors which may be important to a potential investor's analysis. Therefore, PA
Consulting Services Inc. cannot, and does not, accept liability for losses
suffered, whether direct or consequential, arising out of any reliance on the
report.
MARKET CHARACTERISTICS
The independent market consultant identified the following characteristics
of the markets in which we intend to sell our output:
- The Western Systems Coordinating Council includes 78 member power systems
and 21 affiliates in 14 states. The Western Systems Coordinating Council
consists of approximately 59 million energy consumers with more than
700,000 GWh of annual consumption.
- Currently, the only centrally organized competitive wholesale energy
market in the Western Systems Coordinating Council is in California. The
generator services market for the remaining portion of the region is
primarily based on bilateral wholesale contracts.
Within the Western Systems Coordinating Council, the Northwest, consisting
of Montana, Washington, Oregon, and Idaho, represents the primary market for
power for the acquired facilities:
- The market for energy in the Northwest is based primarily on bilateral
contracts between energy producers and energy purchasers. The market also
includes (1) two informal spot markets with survey data reported daily
called the California-Oregon Border and Mid-Columbia spot markets, (2) a
formal short-term spot market called the APX/Chelan Mid-Columbia spot
market and (3) two formal futures markets called the NYMEX
California-Oregon Border and Mid-Columbia Electricity futures markets.
There are currently no markets for ancillary services in the Northwest,
other than through individual contracts between the service providers and
purchasers.
- Utilities in the Northwest are members of the Northwest Power Pool, a
voluntary reserve group. Energy producers have limited direct access to
retail customers in the Northwest.
- Because of the mild climate in the Northwest, electricity demand in the
winter increases significantly.
- The Northwest, and the rest of the Western Systems Coordinating Council,
is unique in the United States in its significant reliance on
hydroelectric generation. Coal-fired generation is the second largest
component of the annual energy generation.
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- The Northwest is also characterized by the dominance of one transmission
owner, the Bonneville Power Administration.
PRICE FORECASTS
The independent market consultant used a production-cost framework and a
capacity compensation market simulation model to forecast energy production and
market prices over the study period in the three pricing areas that are the
primary markets for energy produced by the Montana portfolio. These pricing
areas are: (1) Montana, the physical location of the Montana portfolio; (2)
Washington and Oregon East, representative of the Mid-Columbia spot market, a
major contractual point of delivery for the energy generated by the Colstrip
facility; and (3) Washington and Oregon West.
The independent market consultant used the following assumptions in its
analysis:
- Peak demand in the Northwest (which for purposes of this summary and the
independent market consultant's report includes Idaho, Montana, northern
Nevada, Oregon, Utah and Washington) is forecasted to grow at an average
annual growth rate of approximately 1% from 2000 through 2029.
- Forecasts of natural gas and oil prices use a consensus fuel price
forecast derived from published fuel price forecasts. The following table
summarizes the fuel price forecasts used in the base case.
DELIVERED FUEL PRICES (2000$/MMBTU)
FUEL REGION 2000 2005 2010 2015 2020 2025
---- ---------- ---- ---- ---- ---- ---- ----
Natural Gas.......... Montana 2.46 2.29 2.48 2.55 2.62 2.68
Oregon 2.46 2.31 2.45 2.53 2.59 2.66
Washington 2.61 2.46 2.60 2.69 2.75 2.82
---------- ---- ---- ---- ---- ---- ----
Fuel Oil No. 2....... Montana 5.93 5.26 5.35 5.57 5.75 5.94
Oregon 5.61 4.92 5.01 5.23 5.42 5.62
Washington 5.96 5.23 5.33 5.56 5.76 5.97
---------- ---- ---- ---- ---- ---- ----
Fuel Oil No. 6....... Montana 3.66 3.30 3.35 3.46 3.56 3.67
Oregon 2.91 2.54 2.59 2.71 2.81 2.91
Washington 3.10 2.70 2.76 2.88 2.99 3.10
- Based on assessments of the status of announced plants, the independent
market consultant has estimated operational capacity additions of 1,756
MW of natural gas-fired combustion turbines and combined cycle units in
the Northwest through 2002. Capacity additions after 2002 are based on
the results of modeling and simulation of developers' decisions.
BASE CASE PRICE FORECASTS
Using the assumptions described above, the independent market consultant
developed a "base case" which reflects its best assessment of future market
conditions. The following table summarizes the independent market consultant's
base case "all-in" price forecasts, which represent energy prices and
capacity-related revenues assuming a 100% load factor expressed in real 2000
dollars.
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ALL-IN PRICE FORECASTS
(2000$/MWH)
2000 2001 2002 2003 2004 2005 2010 2015 2020
------ ------ ------ ------ ------ ------ ------ ------ ------
Montana................. $26.70 $26.50 $26.60 $26.00 $26.90 $25.00 $25.70 $26.00 $26.40
Washington and Oregon
East.................. $29.30 $28.90 $28.50 $28.00 $28.70 $27.10 $26.90 $27.30 $27.20
Washington and Oregon
West.................. $29.90 $29.40 $29.00 $28.50 $29.30 $27.60 $27.30 $27.70 $27.50
SENSITIVITY CASES
The independent market consultant also analyzed the following two
alternative cases which test the sensitivity of the base case market price
forecasts:
- "Low Fuel Prices Case," which tests the sensitivity of the base case
market price forecasts to lower gas and oil prices, represented as a
$0.50/MMBtu reduction in the 2000 gas and oil prices with escalation and
coal prices remaining unchanged.
- "High Hydro Case," which reflects the result of five consecutive seasons
of high water availability (2000-2004) in the Western Systems
Coordinating Council. The high water availability data is based on the
average of the two highest years in the past ten years. After the initial
five years, the case reverts back to the base case which is based on the
average water flows over the last ten years.
The following tables show the effects of these alternative assumptions on
the prices forecasted in the base case.
LOW FUEL PRICES CASE
ALL-IN PRICE FORECASTS
(2000$/MWH)
2000 2001 2002 2003 2004 2005 2010 2015 2020
------ ------ ------ ------ ------ ------ ------ ------ ------
Washington and Oregon
East.................. $27.10 $26.80 $26.00 $24.10 $25.60 $23.40 $23.40 $23.70 $23.50
Washington and Oregon
West.................. $27.60 $27.30 $26.40 $24.60 $26.00 $23.80 $23.80 $24.00 $23.80
HIGH HYDRO CASE
ALL-IN PRICE FORECASTS
(2000$/MWH)
2000 2001 2002 2003 2004 2005 2010 2015 2020
------ ------ ------ ------ ------ ------ ------ ------ ------
Washington and Oregon
East.................. $26.70 $26.30 $25.30 $26.60 $26.30 $27.10 $26.90 $27.10 $27.20
Washington and Oregon
West.................. $27.10 $26.70 $25.70 $27.00 $26.70 $27.70 $27.40 $27.60 $27.50
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SUMMARY OF INDEPENDENT FUEL CONSULTANT'S REPORT
Our independent fuel consultant, John T. Boyd Company, has prepared a
report and an update letter, copies of which are set forth as Appendix C to this
prospectus. Following is a summary of the conclusions reached by the independent
fuel consultant in its report. The independent fuel consultant's conclusions are
subject to the assumptions and qualifications set forth in the independent fuel
consultant's report, and you should read this summary in conjunction with the
full text of the independent fuel consultant's report. The descriptive terms
used in this summary may differ from the terms we use elsewhere in this
prospectus. Terms that are not defined in this summary or elsewhere in this
prospectus are defined in the independent fuel consultant's report.
The independent fuel consultant has expressed the following opinions:
- The coal for the Colstrip facility is supplied from Western Energy
Company's Rosebud Mine in southeastern Montana. There are adequate coal
reserves available to satisfy current contractual commitments to the
Colstrip facility, and the Rosebud Mine reserves and resources beyond
those currently committed are adequate to fuel the Colstrip facility
through 2030. Western Energy's property ownership is such that all
reserves are effectively controlled.
- Coal reserve quality is well defined, meets contract specifications and
is similar to that currently burned at the Colstrip facility.
- The Rosebud Mine has all required permits and is generally in compliance
with applicable laws and regulations. No material environmental
deficiencies were found relative to current and future operations.
- The Rosebud mining equipment and facilities are functional and
appropriate for planned operations.
- Current mining plans are reasonable and consistent with the "least-cost"
mining approach. This will result in relatively low costs initially,
followed by gradually increasing costs over the mine life.
- Coal sales at the Colstrip facility are governed by two long-term supply
contracts. Both are full requirements contracts. Thus, pricing is
generally not affected by external market trends.
- The Corette plant obtains fuel from the large mines in the Southern
Powder River Basin under short-term agreements.
- The following table describes the existing fuel supply contracts for the
Colstrip facility:
PLANT FUEL SUPPLIER CONTRACT TERM ESTIMATED 2000 (JULY-DECEMBER) PRICE
----- -------------- -------------------- ----------------------------------------------
Colstrip units 1 and 2.... Western Energy December 31, 2009 $8.32/ton, or $0.49/MMBtu.(1)
Colstrip units 3 and 4.... Western Energy December 31, 2019 $9.12/ton, or $0.54/MMBtu.(2)
- ---------------
(1) The pricing is based on fixed charges plus specified variable charges. A
price re-opener will occur on July 30, 2001. If the parties are unable to
agree on base price provisions, the matter will be arbitrated so as to be
equitable to all parties and will reflect the seller's reasonable cost of
mining.
(2) The pricing is based on a formula which includes fees, incentives and return
on investment compensation. There is no price re-opener provision.
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DESCRIPTION OF OUR PRINCIPAL CONTRACTUAL ARRANGEMENTS
COLSTRIP FACILITY PROJECT AGREEMENTS
Joint ownership of the Colstrip facility
Prior to our acquisition of the Montana Portfolio, interests in the
Colstrip facility were owned by MPC, Puget, Portland, Avista and PacifiCorp,
pursuant to various ownership and operating agreements described below. When we
acquired MPC's interest in the Colstrip facility, we also assumed MPC's rights
and obligations with respect to all such contractual arrangements, with the
exception of the MPC Colstrip unit 4 lease and MPC's related interest in the
common facilities. In addition, we were designated the "operator" of the
Colstrip facility under those agreements when we acquired the Montana portfolio.
Colstrip units 1 and 2 ownership and operating agreements
Puget currently owns a 50% undivided interest and we lease the other 50%
undivided interest in Colstrip units 1 and 2. These undivided interests are held
as tenants-in-common pursuant to the Colstrip Units 1 and 2 Construction and
Ownership Agreement dated as of July 30, 1971, which we refer to as the Colstrip
units 1 and 2 ownership agreement. The Colstrip Units 1 and 2 Agreement for the
Operation and Maintenance of Colstrip Steam Electric Generating Plant dated as
of July 30, 1971, which we refer to as the Colstrip units 1 and 2 operating
agreement, governs the operation of Colstrip units 1 and 2. Both of these
agreements are to remain in effect so long as Colstrip units 1 and 2 are used or
useful for generating energy. The Colstrip units 1 and 2 ownership and operating
agreements provide for an owners' committee for Colstrip units 1 and 2 which
facilitates communication among the owners. When we closed the acquisition of
the Montana portfolio, the owners' committee appointed us operator of Colstrip
units 1 and 2 with broad power to act on Puget's behalf.
Most of the responsibility for operating Colstrip units 1 and 2 is vested
in us, as the operator. The role of the owners' committee in operating Colstrip
units 1 and 2 is limited to scheduling planned outages, reviewing the annual
operation and maintenance costs that we incur and approving the annual budget
that we propose. We must submit a budget to the owners' committee each year
setting out the expected operation and maintenance costs for the coming year. It
also must detail the expenses required for extraordinary items of maintenance.
The owners cannot unreasonably withhold their approval of the budget. If the
owners are unable to reach agreement regarding the budget or any other matter on
which they must agree, they must submit the matter to binding arbitration within
30 days of when the dispute arises. The arbitrator must render his decision
within 30 days from when the owners submit the dispute to him.
Each owner must supply working capital, as required, for operation and
ordinary maintenance. The owners review the amount of working capital
periodically, to determine if the amount is adequate. Also, we pay the operation
and maintenance costs under the budget, and bills the owners for their share of
those costs each month. If either owner fails to make any payment required under
these agreements, it is in default. Even if an owner disputes that it is in
default, the Colstrip units 1 and 2 ownership and operating agreements require
the owner to make the required payments, but allows it to make the payments
under protest. The owners must adjust any payments made under protest when they
settle the underlying controversy regarding the alleged default.
The Colstrip units 1 and 2 ownership and operating agreements provide the
owners of Colstrip units 1 and 2 with rights of first refusal in respect of
transfers and assignments of ownership interests in Colstrip units 1 and 2. No
owner may transfer or assign its interest in Colstrip units 1 and 2 unless it
simultaneously transfers its rights under other project agreements relating to
Colstrip units 1 and 2 to the same party, except with respect to the transfers
and assignments specified in the agreements.
If the Colstrip units 1 and 2 are damaged or destroyed beyond repair and if
either owner does not elect to reconstruct the units, the owner who does not
elect to reconstruct the units may convey its ownership interest in the units to
the electing owner and the electing owner shall pay the other owner the fair
market value of the units.
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We are reimbursed for our costs associated with operating and maintaining
Colstrip units 1 and 2, but do not receive any additional compensation for our
services. We may not assign our responsibilities as operator without Puget's
written approval. Each owner is severally liable for its obligations and losses
under these agreements.
Colstrip units 3 and 4 ownership and operating agreement
The Colstrip Units 3 and 4 Ownership and Operation Agreement dated as of
May 6, 1981 among MPC, Puget, Portland, Avista, PacifiCorp and us governs the
ownership and operation of Colstrip units 3 and 4. We refer to this agreement as
the Colstrip units 3 and 4 ownership and operating agreement. Under this
agreement, the owners hold their undivided interests in Colstrip units 3 and 4
as tenants-in-common.
We own a 30% leasehold interest in Colstrip unit 3. The other owners'
respective percentage interests in each of Colstrip units 3 and 4 are as
follows:
- MPC owns a 30% leasehold interest in Colstrip unit 4;
- Puget owns 25% of each of Colstrip units 3 and 4;
- Portland owns 20% of each of Colstrip units 3 and 4;
- Avista owns 15% of each of Colstrip units 3 and 4; and
- PacifiCorp owns 10% of each of Colstrip units 3 and 4.
We refer to these owners and ourselves as the project users. The Colstrip
units 3 and 4 ownership and operating agreement is to remain in effect so long
as Colstrip units 3 and 4 are capable of producing energy. The Colstrip units 3
and 4 ownership and operating agreement is independent of the agreements
governing Colstrip units 1 and 2.
Pursuant to the Colstrip units 3 and 4 ownership and operating agreement,
each project user has a "project share" in Colstrip units 3 and 4 equal to the
sum of (1) any undivided interests in Colstrip units 3 and 4 owned by such
project user, and (2) any undivided interests in Colstrip units 3 and 4 leased
to such project user by a third-party owner. Each project user is entitled to
schedule and take an amount of generation up to but not exceeding its project
share of the net energy generation capacity of Colstrip units 3 and 4. The
project shares are subject to adjustment under certain limited circumstances as
described in the Colstrip units 3 and 4 ownership and operating agreement. Under
the reciprocal sharing agreement between us and MPC described below, our 30%
leasehold interest in Colstrip unit 3 entitles us to a 15% project share of the
energy generation capacity of the combined Colstrip units 3 and 4.
The Colstrip units 3 and 4 ownership and operating agreement provides for
the governance of Colstrip units 3 and 4 through a project committee and sets
out specific matters that require approval of the project committee. Other
matters are under our control, as operator of Colstrip units 3 and 4. The
matters that require project committee approval include setting the annual
budget, deciding whether to repair damage to Colstrip units 3 and 4 when the
damage exceeds $2 million, setting the budget for repairing such damage and
settling third party claims against Colstrip units 3 and 4 when the claims
exceed $0.5 million.
Voting rights correspond to each party's project share, which as described
above will include our leasehold interest in Colstrip unit 3 and MPC's leasehold
interest in Colstrip unit 4. In most cases, approval of both (1) our committee
member, and (2) at least two other committee members is sufficient to approve
matters coming before the project committee so long as such committee members
voting for approval represent at least 55% of the total project shares. In
certain limited circumstances, however, approval by a larger project share is
required. In order to replace us as the operator, committee members representing
at least 65% of the total project shares must approve such replacement.
Improvements to Colstrip units 3 and 4 that go beyond what is needed to assure
design capability and reliability or what is required by governmental agencies,
require approval by committee members representing at least 85% of the total
project shares. Dispute resolution is by arbitration with a single arbitrator.
Subject to requirements in the Colstrip units 3 and
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4 ownership and operating agreement, any two members of the project committee
(other than the member appointed by us) may together submit any proposal to the
committee.
Each of Puget, Portland, Avista and PacifiCorp is able to appoint one
member to the project committee. Under the terms of a vote sharing agreement
between MPC and us, MPC and we jointly control the remaining vote on the project
committee. Under the MPC Colstrip unit 4 lease, as long as the MPC Colstrip unit
4 lease remains in effect, the owner lessors under this lease are not involved
in the governance of Colstrip units 3 and 4 through the project committee. MPC
and we can each appoint a member of the project committee, but those appointees
share a single vote for their 30% project share. In matters primarily affecting
Colstrip unit 3, our appointee casts the shared vote, while in matters primarily
affecting Colstrip unit 4, MPC's appointee casts the shared vote. In matters
that affect both Colstrip units 3 and 4, our appointee casts the shared vote,
unless MPC objects. If MPC's objection involves a judgment as to how the project
ought to be operated, then the project committee will conduct a poll of the
members of the project committee. If members of the project committee
representing enough project shares to carry the vote indicate that they intend
to vote against MPC's objection, then our appointee casts the shared vote;
otherwise, MPC's appointee casts the shared vote. If MPC's objection pertains to
a default under the Colstrip unit 4 lease or the categorization of the matter
under consideration by the project committee as one affecting both Colstrip
units 3 and 4, and MPC and we cannot settle the disagreement, then the dispute
must be resolved by arbitration. The vote sharing agreement is effective until
the Colstrip units 3 and 4 ownership and operating agreement is amended to allow
MPC and us to vote our respective project shares separately or until the owner
lessors under the MPC Colstrip unit 4 lease take possession of Colstrip unit 4
pursuant to the lease. If the owner lessors under the MPC unit 4 lease take
possession by foreclosing on the Colstrip unit 4 lease after an event of default
under the lease, the owner lessors will direct the shared vote. Otherwise, MPC
and the owner lessors are required to attempt to reach agreement on the
allocation of the unit 4 project share vote. If they cannot settle a
disagreement, then the dispute must be resolved by arbitration.
Under the Colstrip units 3 and 4 ownership and operating agreement, as
successor to MPC, we were appointed operator of Colstrip units 3 and 4 with
broad power to act on behalf of the other owners of Colstrip units 3 and 4. We
are reimbursed for costs associated with operating and maintaining Colstrip
units 3 and 4, but do not receive any additional compensation for our services.
We may not assign our responsibilities without the written approval of project
committee members representing at least 50% of the total project shares
(excluding our project share). We may resign as the operator upon the giving of
two years' notice to the other project users, and may be replaced by the project
committee upon approval of project committee members representing at least 65%
of the total project shares. However, no replacement of us as the operator shall
become effective earlier than two years from the date of such approval unless we
consent or an arbitrator finds us in material breach of our obligations.
The Colstrip units 3 and 4 ownership and operating agreement provides the
owners of Colstrip units 3 and 4 rights of first refusal in respect of transfers
and assignments of ownership interests in Colstrip units 3 and 4. No project
user may transfer or assign its interest in Colstrip units 3 and 4 unless it
simultaneously transfers its rights under other project agreements relating to
Colstrip units 3 and 4 to the same party, except the transfers and assignments
that are specifically permitted in the agreement.
If Colstrip units 3 and 4 are damaged, the Colstrip units 3 and 4 ownership
and operating agreement provides a different procedure for approving repairs
depending on how severe the damage is. If the cost of repairing the damage is
less than 20% of the value of Colstrip units 3 and 4 after taking depreciation
into account, then we must submit a budget to the project committee. This budget
is dealt with under the general provisions of the Colstrip units 3 and 4
ownership and operating agreement relating to the budget approval procedures. If
the cost of repairing the damage is greater than 20%, then the Colstrip units 3
and 4 ownership and operating agreement provides a special procedure that
requires the unanimous consent of the project users. If all of the project users
agree to pay for the repairs, then the Colstrip units 3 and 4 ownership and
operating agreement prescribes the same approval process as for more minor
damage. If only some of the owners want to repair the damage, however, then the
project share of those who do not contribute towards the repairs will be
correspondingly reduced and redistributed to those who do contribute. The amount
of the
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distribution is based on the cost of the repairs and the fair market value of
Colstrip units 3 and 4 without the repairs.
Each project user is required to contribute its project share of the costs
of operation for Colstrip units 3 and 4 to a bank account. These costs of
operation include payroll, material and supply costs, taxes and all costs
related to injury or damages (after subtracting the proceeds of any insurance).
We can use the funds in this account to meet the operating and maintenance
expenses of Colstrip units 3 and 4. We must periodically give each project user
notice of the amount that we need to cover expenses. The project user must
deposit its project share of this amount in the account, regardless of whether
the expenses are covered in the budget. If the project user fails to make this
deposit, or any other payment required by the Colstrip units 3 and 4 ownership
and operating agreement, then it will be in default. If the project user does
not pay within a specified period of time, and the project users cannot resolve
the dispute, then the matter must go to arbitration.
As long as the default is in dispute, the defaulting project user is not
entitled to the energy generated by its project share of Colstrip units 3 and 4.
We can sell the energy generated by the defaulting project user's project share,
and apply the proceeds of the sale to the amount the defaulting project user
owes.
Reciprocal sharing agreement
When we closed the acquisition of the Montana portfolio, we and MPC entered
into the MPC/PPL Units 3&4 Generating Project Reciprocal Sharing Agreement,
which we refer to as the reciprocal sharing agreement, to govern each party's
responsibilities regarding the operation of Colstrip units 3 and 4. Whereas the
vote sharing agreement controls our right to vote on the Colstrip units 3 and 4
project committee, the reciprocal sharing agreement governs our economic rights
and responsibilities with respect to Colstrip units 3 and 4. This agreement
provides that subject to the provisions of the Colstrip units 3 and 4 ownership
and operating agreement, MPC and we each hold a 15% project share in Colstrip
units 3 and 4, and each party is entitled to take 15% of the energy generation
capacity of Colstrip units 3 and 4. Each party is also responsible for taking or
otherwise disposing of 15% of the minimum energy production from Colstrip units
3 and 4, and for most costs of operation and costs of construction under the
Colstrip units 3 and 4 ownership and operating agreement, irrespective of
whether a particular cost is specific to Colstrip unit 3 or 4. However, each
party pays its own fuel related costs. This agreement will remain in force until
the owner lessors under the Colstrip unit 4 lease take possession of Colstrip
unit 4 pursuant to the MPC Colstrip unit 4 lease.
Common facilities agreement
The Colstrip owners are parties to the Common Facilities Agreement -- Units
1, 2, 3 and 4 dated May 6, 1981, which we refer to as the common facilities
agreement. The common facilities agreement addresses common ownership and
operating issues between Colstrip units 1 and 2 and Colstrip units 3 and 4. We
succeeded MPC as the operator of the Colstrip common facilities when we acquired
the Montana portfolio.
The common facilities agreement allocates costs associated with the
Colstrip common facilities between Colstrip units 1 and 2 and Colstrip units 3
and 4 and sets out our rights and obligations with respect to the Colstrip
common facilities. The cost percentage allocations differ depending on the type
of facility at issue. There is not a separate common facilities owner committee.
Rather, we must seek approval from both the Colstrip units 1 and 2 owners'
committee and the Colstrip units 3 and 4 project committee regarding several
matters relating to the Colstrip common facilities, including the annual budget,
which approval may not be unreasonably withheld. We are reimbursed our costs
associated with operating and maintaining the Colstrip common facilities, but
receive no fee. We may not assign our responsibilities as the operator without
the consent of both the Colstrip units 1 and 2 owners' committee and the
Colstrip units 3 and 4 project committee, and if we are replaced as operator
under the Colstrip units 3 and 4 ownership and operating agreement we shall be
removed as operator of the Colstrip common facilities. The common facilities
agreement will remain in effect until the end of the term of either the Colstrip
units 1 and 2 ownership agreement or the Colstrip units 3 and 4 ownership and
operating agreement, whichever is earlier. However, the portion of the common
facilities agreement by which the parties waive their right to partition shall
survive until the end of the term of
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both the Colstrip units 1 and 2 ownership agreement and the Colstrip units 3 and
4 ownership and operating agreement.
Colstrip units 1 and 2 coal supply agreement
Western Energy, Puget and we are parties to the Coal Supply Agreement dated
as of July 30, 1971, which we refer to as the Colstrip units 1 and 2 coal supply
agreement, to supply coal to Colstrip units 1 and 2. We are responsible for
transporting the coal from Western Energy's facility near Colstrip, Montana to
the Colstrip facility. We transport the coal to the Colstrip facility with coal
haulers and by a conveyor belt. The agreement is a requirements contract, under
which Western Energy will supply all of the coal that Colstrip units 1 and 2
need to operate, from a minimum of 1.5 million tons up to a maximum of 3 million
tons each calendar year.
The price for coal under this agreement is broken down into a commodity
charge, which is paid for each ton of coal produced, and an annual fixed charge,
which is paid in twelve equal monthly installments. The commodity charge covers
Western Energy's costs of wages and benefits, salaries, reclamation, materials
and supplies, lease, rents and records and energy. The fixed price charge is
subject to renegotiation on July 30, 2001. The fixed charge consists of rates of
compensation for administrative employees, ad valorem taxes and depreciation.
The commodity charge is adjusted as of March 1 and September 1 of each year
based on changes in Western Energy's costs; there is also an adjustment for
inflation. If the parties are unable to agree on a base price by January 30,
2002, the matter will be arbitrated so as to be equitable to all parties and to
reflect Western Energy's reasonable costs of mining.
The agreement extends through December 31, 2009, although it may be
extended upon terms mutually agreeable to the parties if Western Energy has coal
economically available for mining.
Colstrip units 3 and 4 coal supply agreement
Puget, Portland, Avista, PacifiCorp, MPC, Western Energy and we are parties
to the Amended and Restated Coal Supply Agreement for Colstrip Units 3 and 4
dated as of August 24, 1998, which we refer to as the Colstrip units 3 and 4
coal supply agreement, to supply coal to Colstrip units 3 and 4.
This agreement is also a requirements contract. It provides that Western
Energy will supply all of the coal that Colstrip units 3 and 4 need to operate,
without a stated minimum or maximum amount. It requires Western Energy to
dedicate all of the coal reserves it owns in Rosebud County Montana, Area C and
to purchase coal not produced from the mine at Rosebud County Montana, Area C,
as the agent of the Colstrip units 3 and 4 owners, to meet the requirements of
Colstrip units 3 and 4.
The coal price under the Colstrip units 3 and 4 coal supply agreement also
includes fixed charge and commodity charge components. These components are
similar to those contained in the Colstrip units 1 and 2 coal supply agreement,
although certain cost allocation and pass-through provisions are different. In
addition, the pricing cannot be renegotiated.
The agreement extends through December 31, 2019, although it may be
extended upon terms mutually agreeable to the parties if Western Energy has coal
economically available for mining.
Colstrip units 3 and 4 coal transportation agreement
Puget, Portland, Avista, PacifiCorp, MPC, Western Energy and we are parties
to the Coal Transportation Agreement for Colstrip Units 3 and 4 dated July 10,
1981, which we refer to as the Colstrip units 3 and 4 coal transportation
agreement, which provides for the transportation of coal from the delivery point
under the Colstrip units 3 and 4 coal supply agreement to Colstrip units 3 and 4
by means of a conveyor belt. The
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agreement extends through December 31, 2019. The fee payable to Western Energy
under the agreement is the sum of:
- the fixed charge, plus
- the cost reimbursement charge, plus
- the operating profit fee, minus
- the revenue credit.
The price is adjusted on March 1 and September 1 of each year to reflect
changes in costs or inflation and for changes in depreciation and property tax
components of the fixed charge. We act as agent for the owners of Colstrip units
3 and 4 in dealings with Western Energy under the Colstrip units 3 and 4 coal
transportation agreement. This agreement does not have a specified term, but
rather remains in effect as long as the Colstrip units 3 and 4 coal supply
agreement does.
Colstrip project transmission agreement
Ownership and operation of the Colstrip transmission system is governed by
the Colstrip Project Transmission Agreement dated as of May 6, 1981 among MPC,
Puget, Portland, Avista and PacifiCorp, which we refer to as the Colstrip
project transmission agreement. Under our asset purchase agreement with MPC, if
we purchase MPC's interest in the Colstrip transmission system associated with
Colstrip units 1, 2 and 3, MPC will also assign to us its rights under the
Colstrip project transmission agreement associated with Colstrip units 1, 2 and
3. Each of the parties holds an undivided interest in each of the two segments
of the Colstrip transmission system as tenants-in-common in proportion to its
payment of costs of construction for such segment. These payments are based on
the ownership percentages that each party holds in Colstrip units 3 and 4, plus
additional payments made by MPC and Puget as owners of Colstrip units 1 and 2.
Such payments are adjusted for transmission system elective capital additions
and transmission system capital additions that the parties make to different
segments of the Colstrip transmission system.
The agreement provides for the governance of the Colstrip transmission
system though a transmission committee. Each party to the agreement (or its
successors and assigns acting collectively) appoints one transmission committee
member. Voting rights are based on each party's "requirements share," which
corresponds to each party's capacity in the transmission system segments. The
transmission committee provisions are very similar to the "project committee"
provisions of the Colstrip units 3 and 4 ownership and operating agreement, and,
like that agreement, the Colstrip project transmission agreement appoints a
separate transmission operator for the Colstrip transmission system. In most
cases (including in connection with the adoption of budgets), approval of both
(1) the transmission operator's committee member, and (2) at least two other
committee members is sufficient to approve matters coming before the
transmission committee so long as such committee members voting for approval
represent at least 55% of the total requirement shares of each segment affected
by the matter before the committee.
The transmission operator has broad powers to act on behalf of the other
transmission owners, subject to the rights of the transmission committee. The
transmission operator may not assign its responsibilities without the approval
of transmission committee members representing at least 50% of the total
requirements shares of each segment affected (excluding the requirements share
of the operator). The transmission operator may resign as operator upon the
giving of two years' notice to the transmission owners. However, unlike the
Colstrip units 3 and 4 ownership and operating agreement, the Colstrip project
transmission agreement does not provide for replacement of the operator by vote
of the other owners.
The Colstrip project transmission agreement may be terminated as to any
owner with respect to such owner after the Colstrip units 3 and 4 ownership and
operating agreement is terminated and if such owner offers to assign all of its
interests to the other transmission owners. Otherwise, the Colstrip project
transmission agreement continues in effect indefinitely.
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Bonneville Power Administration Montana intertie agreements
MPC, Puget, Portland, Avista and PacifiCorp are parties to transmission
agreements with the United States of America, acting through the Bonneville
Power Administration, dated April 6, 1981 known as the Montana intertie
agreements. Under our asset purchase agreement with MPC, if we purchase an
interest in the Colstrip transmission system from MPC, MPC will also partially
assign to us its rights under the Montana intertie agreements. These agreements
will provide us with transmission rights on the Bonneville Power Administration
Montana intertie. Pursuant to the terms of these agreements, the Bonneville
Power Administration charges a use-of-facilities fee to the users based on
investment in, and operating costs of, the portion of the Bonneville Power
Administration Montana intertie from Townsend to Garrison. The fees are charged
to the users pro rata based upon capacity rights in the Bonneville Power
Administration Montana intertie.
THE ASSET PURCHASE AGREEMENT
We, as assignee of PPL Global, purchased the Montana portfolio from MPC for
approximately $760 million plus transaction expenses on December 17, 1999. The
asset purchase agreement also provides that, except to the extent of the express
representations and warranties of MPC in the asset purchase agreement, we
acquired the Montana portfolio "as is, where is."
Contingent obligations
We are required under the asset purchase agreement with MPC to purchase its
interest in the Colstrip transmission system associated with Colstrip units 1, 2
and 3 for $97 million. Purchasing this interest from MPC would give us owned
transfer capability of 612.8 MW on the Colstrip to Broadview segment and 210 MW
on the Broadview to Townsend segment. We are currently in discussions with MPC
to pursue alternatives to acquiring this entire interest in the Colstrip
transmission system as contemplated by the asset purchase agreement. However, if
we do purchase MPC's interest in accordance with the original terms, we have a
commitment from PPL Corporation to provide us with an additional equity
contribution of up to $97 million to fund the acquisition.
Liabilities
Under the asset purchase agreement, we agreed to assume certain liabilities
relating to the Montana portfolio including post-closing liabilities under
assumed contracts and post-closing employment obligations and environmental
liabilities. We also assumed responsibility for losses resulting from or arising
out of any pre-existing environmental condition or violation of environmental
law relating to the Montana portfolio, other than losses relating to Are-closing
fines and penalties, the off-site release of hazardous substances and certain
liabilities relating to the Thompson Falls hydroelectric project. We are not
obligated to assume any liability under the asset purchase agreement arising out
of or related to the assets or liabilities retained by MPC.
Representations and warranties
The asset purchase agreement provides that the parties' respective
representations and warranties (other than those with respect to tax, ERISA and
title) survive until December 17, 2000. The representations and warranties with
respect to tax and ERISA survive for the periods of the applicable statutes of
limitation, and the representations with respect to title survive indefinitely.
However, if we actually receive proceeds from title insurance for real property
included in the Montana portfolio in respect of any matters addressed by title
representations and warranties, then we will not be indemnified by MPC to the
extent that we are compensated from such proceeds and to the extent such
proceeds relate to those representations and warranties.
Indemnification
The asset purchase agreement provides that, subject to the limitations
discussed below, MPC will indemnify us and our affiliates, and our respective
officers, directors, employees, agents and representatives
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from and against any and all losses suffered, incurred, or sustained by any of
them resulting from or arising out of:
- any breach by MPC of any representation or warranty of MPC contained in
the asset purchase agreement;
- any breach by MPC of any covenant or agreement of MPC contained in the
asset purchase agreement;
- the liabilities not assumed by us under the asset purchase agreement; or
- liabilities relating to certain employee severance agreements.
MPC's indemnification obligations are subject to the following limitations.
MPC shall have no obligation to indemnify us for losses related to MPC's breach
of representations other than title representations until the aggregate amount
of such losses equals or exceeds $5 million. In addition, MPC's liability for
losses may not exceed in the aggregate 50% of the purchase price of the Montana
portfolio. MPC's liability for breach of its title representations may not
exceed, in the aggregate, the purchase price of the Montana portfolio.
Under the asset purchase agreement, we assumed responsibility for losses
resulting from or arising out of pre-existing environmental conditions or
violations of environmental laws relating to the Montana portfolio. However, MPC
has retained liability related to its hazardous materials which either are
transported off-site or released off-site. MPC has agreed to indemnify us for
losses relating to pre-existing on-site environmental conditions, including any
fines or penalties imposed upon us by a governmental authority relating to MPC's
ownership, operation and maintenance of the Montana portfolio. MPC has also
agreed to indemnify us if the Montana Department of Environmental Quality
requires us to remediate metals at the Thomspon Falls facility or changes the
regulatory status of the Thompson Falls facility.
These indemnity obligations are limited and are not transferred to the
owner lessors. Also, MPC's obligation to indemnify us for losses associated with
the cost of remediating pre-existing on-site environmental conditions is limited
to 50% of MPC's pro-rata share of such environmental liability and may not
exceed in the aggregate 10% of the purchase price of the Montana portfolio.
MPC's obligation to indemnify us for losses relating to the remediation of
on-site environmental conditions not identified in the Phase II reports prepared
by MPC's consultant is limited to losses for which indemnity claims are made
within two years after the closing of the acquisition.
The asset purchase agreement also provides that we will indemnify MPC and
its affiliates, and their respective officers, directors, employees, agents and
representatives, from and against any and all losses suffered, incurred, or
sustained by any of them resulting from or arising out of:
- any breach by us of any representation or warranty of ours contained in
the asset purchase agreement;
- any breach by us of any covenant or agreement of ours contained in the
asset purchase agreement; or
- the liabilities assumed by us under the asset purchase agreement.
Our indemnification obligations are subject to the following limitations.
We shall have no obligation to indemnify MPC for losses related to our breach of
representations until the aggregate amount of such losses equals or exceeds $5
million, and our liability for such losses shall not exceed in the aggregate 50%
of the purchase price of the Montana portfolio.
Pollution control facilities
The asset purchase agreement contains use limitations on those portions of
the Colstrip facility that were financed by certain outstanding pollution
control revenue funding bonds which we refer to as the pollution control
facilities. These use limitations prohibit us, until the maturity or redemption
date of the outstanding pollution control revenue funding bonds, from materially
changing (or permitting any such change to) the character or nature of the use
of the pollution control facilities from the manner in which they had been used
prior to our acquisition of the assets, unless such changed use would constitute
a permissible use or purpose for which tax-exempt bonds could be issued pursuant
to the Tax Reform Act of 1986. In addition, we may not sell
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or otherwise transfer the pollution control facilities unless (1) the transferee
covenants to satisfy the use limitations or (2) the transfer relates to personal
property and is exclusively for cash, the proceeds of which will be expended
within six months of the date of receipt on facilities for which tax-exempt
bonds could be issued pursuant to the Tax Reform Act of 1986. The use
limitations do not, however, prevent us or a transferee from ceasing to use any
pollution control facilities that, in such person's reasonable judgment, have
become obsolete or otherwise uneconomical to continue to use.
OTHER AGREEMENTS
Interconnection agreement
We have entered into an interconnection agreement with MPC pursuant to
which MPC provides us with transmission interconnection services. The agreement
sets forth various requirements for the capabilities and operation of the
Montana portfolio to ensure the reliability of MPC's transmission system. The
interconnection agreement will terminate on the earliest of (1) termination of
all agreements between MPC and us for the provision of transmission service
under MPC's open-access tariff, (2) the date the parties mutually agree in
writing to terminate the agreement or (3) the effective date of an agreement
between an independent system operator and us. If MPC enters into an agreement
with an independent system operator whereby the independent system operator
acquires the right to control MPC's energy system, we must enter into a new
interconnection agreement with that independent system operator and the
interconnection agreement will be terminated.
Energy purchase agreements
We are supplying energy to MPC under two energy purchase agreements. The
Colstrip Unit Number 3 Wholesale Transition Service Agreement covers a 200 MW
load and expires December 17, 2001. The Non Colstrip Unit Number 3 Wholesale
Transition Service Agreement requires us to supply MPC's actual remaining
customer load for each hour; it expires when MPC's remaining customer load is
zero, but in no event later than June 30, 2002. Under both of these agreements,
in a given month we are paid the weighted average of the Mid-Columbia index
price over the last consecutive 12 months for energy, subject to a floor of $20
per MWh and a cap of $22.25 per MWh.
PPL EnergyPlus wholesale brokering and contract management agreement
We have executed a brokering and contract management agreement with PPL
EnergyPlus. The agreement authorizes PPL EnergyPlus to act as our exclusive
agent in managing our wholesale energy supply and energy and capacity purchase
contracts, including our energy purchase agreements with MPC. The agreement also
grants PPL EnergyPlus express authority and responsibility for managing the sale
of energy in excess of our wholesale contract commitments.
Under the terms of the agreement, PPL EnergyPlus must execute wholesale
transactions in our name, schedule and/or confirm the scheduling of energy in
connection with wholesale transactions, procure transmission service and
associated ancillary services on our behalf, and perform contract management
services. We are responsible for providing PPL EnergyPlus with necessary
information for us to continue to receive transmission service, complying with
requirements of transmission tariffs and regulators, and paying the transmission
providers for the transmission service PPL EnergyPlus obtains for us. We retain
title to all of the Montana portfolio energy that is sold into the wholesale
market.
We must pay PPL EnergyPlus a fee to cover its annual operating expenses
related to its responsibilities under the brokering and contract management
agreement. All revenue from energy sales flows directly to us. The fee was
approximately $5.1 million in 2000 and is expected to increase to approximately
$5.5 million in 2005. The agreement provides that at the end of each year, the
amount we paid PPL EnergyPlus during that year will be adjusted to reflect PPL
EnergyPlus' actual operating expenses for that year. If PPL EnergyPlus' actual
expenses are greater than the fee we paid, then we will pay PPL EnergyPlus the
excess amount we owe. If its actual expenses are less, PPL EnergyPlus will
reimburse us.
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Either party can terminate the agreement on 60 days' written notice.
PPL EnergyPlus retail brokering memorandum of understanding
We have entered into a memorandum of understanding with PPL EnergyPlus
regarding our supply of energy to satisfy PPL EnergyPlus' obligations under its
retail contracts. This memorandum of understanding was effective through
December 31, 2000. We intend to renew this memorandum of understanding with
substantially the same terms. We intend to enter into wholesale energy
agreements with PPL EnergyPlus based on this memorandum of understanding. The
memorandum of understanding provides that we will supply the energy necessary
for PPL EnergyPlus to supply energy services to retail customers. We have the
ability to sell any portion of the energy generated by the Montana portfolio to
PPL EnergyPlus under the memorandum of understanding, taking into account our
energy commitments to third parties under wholesale supply agreements. PPL
EnergyPlus will take title to the energy and has the sole authority to sell the
energy, including the sole responsibility for any sales and retail customer
credit risk.
The memorandum of understanding provides for two different pricing
mechanisms, dependent on the structure of PPL EnergyPlus' underlying retail
contract structure. If PPL EnergyPlus sells to a retail customer at a fixed
price during the contract term, we will supply energy to PPL EnergyPlus for that
contract term at the Mid-Columbia forward price agreed by us and PPL EnergyPlus
at the date the retail supply contract is executed. If PPL EnergyPlus enters
into a floating price agreement with a retail customer, we will supply energy to
PPL EnergyPlus for the term of the contract at a floating price. The floating
price that PPL EnergyPlus will pay us will be the Mid-Columbia forward price
plus $1.00. Should PPL EnergyPlus enter into a retail contract to sell energy at
a price that is structured with both fixed and floating components, we will use
a combination of the above pricing mechanisms.
Credit facility
On November 16, 1999 we entered into a credit facility with various
commercial banks and The Chase Manhattan Bank as administrative agent for the
banks. The credit facility included a bridge facility, a revolving acquisition
facility and a working capital facility.
The bridge facility is a 364-day senior unsecured credit facility. We had
$360 million outstanding under this facility, which was repaid with the proceeds
from the sale of the leased assets. We cancelled the remaining unused commitment
under the bridge facility. Borrowings under the bridge facility were used
primarily to finance a portion of our acquisition of the Montana portfolio. In
accordance with SFAS 4, "Reporting Gains and Losses from Extinguishment of
Debt," an extraordinary item was recorded in the year ended December 31, 2000
for approximately $1.0 million of deferred loan fees that were written off in
connection with repayment of the bridge facility, which is net of income taxes
of $0.65 million.
The revolving acquisition facility was a three-year senior unsecured credit
facility. We cancelled the full amount of the commitments under this facility.
The working capital facility is a three-year senior unsecured credit
facility. We have the ability to borrow up to $100 million under the working
capital facility. Borrowings under the working capital facility are being and
will be used for our general corporate purposes.
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DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES
GENERAL
As used in this description, the term "certificates" refers to the new
certificates to be issued in the exchange offer. Each certificate will represent
a fractional, undivided interest in the pass through trust and will correspond
to a pro rata share of the property of the pass through trust, including the
outstanding principal amount of the lessor notes. The property of the pass
through trust will consist solely of the lessor notes, all monies due or paid
on, or the liquidation proceeds of, the lessor notes and other moneys deposited
with the pass through trustee.
The certificates, other than certificates sold to institutional accredited
investors, will be issued in book-entry form. Persons owning a beneficial
interest in the certificates are referred to as certificate owners. Certificate
owners, other than institutional accredited investors, will not be entitled to
receive a definitive certificate representing the certificate owner's interest
in the certificates, except as described below under the caption "--Book entry;
delivery and form." Unless and until definitive certificates are issued under
the limited circumstances described later in this prospectus, all references to
actions by registered certificate holders mean actions taken by The Depository
Trust Company or, DTC, upon instructions from its participants, and all
references made herein to distributions, notices, reports and statements to
certificate holders will refer to distributions, notices, reports and statements
to DTC or its nominee, Cede & Co., as the registered holder of the certificates,
or to DTC participants for distribution to certificate owners in accordance with
DTC procedures. You should consult with each bank or broker through which you
hold a beneficial interest in a certificate for information on how you will
receive notices and payments with respect to your certificates.
We have formed the pass through trust for the exclusive purpose of issuing
the certificates. The pass through trust will have no property other than the
trust property described above. Each certificate will represent an interest in
the pass through trust and will not represent an interest in or obligation of
us, the pass through trustee, the owner lessors (except to the extent of the
trust property) or the owner investors, or any affiliates of any of the
foregoing. The pass through trustee will make distributions to the certificate
holders solely from the trust property to the extent the trust property contains
sufficient proceeds to make the distributions. By accepting a certificate, each
certificate holder agrees that it will look only to the income and proceeds of
the trust property to the extent available for distribution.
REGISTRATION RIGHTS; LIQUIDATED DAMAGES
We and the initial purchasers entered into the registration rights
agreement on July 20, 2000. Under the registration rights agreement, we agreed
to file with the SEC the exchange offer registration statement of which this
prospectus is a part under the Securities Act with respect to an exchange offer
to the holders of restricted certificates.
Upon the effectiveness of the exchange offer registration statement, the
pass through trust will offer new certificates in exchange for restricted
certificates to the holders of restricted certificates who are able to make
certain representations.
Shelf registration statement. We agreed to use our reasonable best efforts
to file, as promptly as practicable, with the SEC and cause to be declared
effective a shelf registration statement relating to the offer and sale of the
transfer restricted certificates by the holders thereof from time to time in
accordance with the methods of distribution set forth in the shelf registration
statement if:
(1) we are not permitted to effect a registered exchange offer because
of a change in law or the applicable interpretations thereof of the staff
of the SEC;
(2) any transfer restricted certificates validly tendered pursuant to
the registered exchange offer are not exchanged for new certificates not
subject to transfer restrictions within 270 days of the closing date;
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(3) any initial purchaser so requests with respect to the certificates
not eligible to be exchanged for new certificates in the registered
exchange offer and held by it following consummation of the registered
exchange offer;
(4) applicable laws or interpretations thereof do not allow any
certificate holder to participate in the registered exchange offer;
(5) any certificate holder that participates in the registered
exchange offer does not receive freely transferable new certificates in
exchange for tendered transfer restricted certificates; or
(6) we so elect.
No certificate holder (other than the initial purchasers) is entitled to
have any transfer restricted certificates held by it covered by the shelf
registration statement unless that certificate holder agrees in writing to be
bound by all the provisions of the registration rights agreement.
Our obligations regarding the exchange offer registration statement. The
registration rights agreement also provides that:
(1) we will prepare and file the exchange registration statement with
the SEC within 90 days after the closing date;
(2) we will use our reasonable best efforts to cause the exchange
offer registration statement to be declared effective within 240 days after
the closing date; and
(3) we will keep the registered exchange offer open for not less than
30 days (or longer if required by applicable law) after the date on which
notice of the registered exchange offer is mailed to certificate holders.
Liquidated damages. Although we have filed an exchange offer registration
statement or a shelf registration statement, we cannot assure you that it will
become effective. If:
- the exchange registration statement or the shelf registration statement,
as applicable, is not declared effective within 240 days after the
closing date, or (A) in the case of a shelf registration statement
required to be filed in response to a change in law or the applicable
interpretations of the SEC staff, if later, within 60 days after
publication of the change in law or interpretation or (B) in the case of
a shelf registration statement required to be filed in response to the
request of any initial purchaser with respect to the certificates not
eligible to be exchanged for new certificates in the registered exchange
offer and held by it following the consummation of the registered
exchange offer, if later, within 60 days of the date of such request;
- the registered exchange offer is not consummated on or prior to 270 days
after the closing date; or
- a shelf registration statement is filed and declared effective within 270
days after the closing date (or (A) in the case of a shelf registration
statement required to be filed in response to a change in law or the
applicable interpretations of the SEC staff, if later, within 60 days
after publication of the change in law or interpretation or (B) in the
case of a shelf registration statement required to be filed in response
to the request of any initial purchaser with respect to the certificates
not eligible to be exchanged for new certificates in the registered
exchange offer and held by it following the consummation of the
registered exchange offer, if later, within 60 days of the date of such
request) but thereafter ceases to be effective (at any time that we are
obligated to maintain the effectiveness thereof) without being succeeded
within 45 days by an additional registration statement filed and declared
effective;
then, until the conditions described above are cured, we will be obligated to
pay liquidated damages to each holder of a transfer restricted certificate in an
amount equal to the interest that would accrue on your portion of the
outstanding principal amount of the lessor notes at 0.50% per year.
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Representations and obligations of certificate holders. Certificate
holders will be required to:
(1) if participating in the registered exchange offer, make certain
representations (as described in the registration rights agreement) to us;
and
(2) if registering certificates pursuant to a shelf registration
statement, deliver information regarding the certificate holders to be
included in the shelf registration statement if required by us.
PAYMENTS AND DISTRIBUTIONS
Scheduled payments. The pass through trustee will pay each certificate
holder a pro rata share of all scheduled principal and interest payments on the
lessor notes received by the pass through trustee. Scheduled payments are to be
made on January 2 and July 2 of each year, commencing January 2, 2001, each
referred to as a scheduled distribution date. The pass through trustee will
establish and maintain with itself, on behalf of and for the benefit of the
certificate holders, one or more non-interest bearing accounts, each a
certificate account, for the deposit of scheduled payments on the lessor notes
held by the pass through trust. Under the pass through trust agreement, the pass
through trustee must immediately deposit any scheduled payments received in the
certificate account.
On each scheduled distribution date, and on each of the following five
days, the pass through trustee will distribute to certificate holders of record
all scheduled payments that it receives before 11:00 a.m., New York time, on the
day it receives the payment or on the following business day if received after
11:00 a.m.
The record date will be the fifteenth day preceding such scheduled
distribution date, subject to certain exceptions. Any scheduled payments
received by the pass through trustee after the fifth day following the scheduled
distribution date will be distributed as a special payment as described below.
Special payments. The pass through trustee will pay each certificate
holder a pro rata share of:
(1) all payments of principal, premium, if any, and interest received
by the pass through trustee because of a partial or full redemption of the
lessor notes, including as a result of the optional or mandatory redemption
of the lessor notes;
(2) amounts received by the pass through trustee following a default
under the lessor notes held in the pass through trust, including payments
received from the sale of lessor notes by the pass through trustee; and
(3) any payment which is not received within five days of the
scheduled distribution date.
We refer to these amounts as special payments. The lessor notes (and
consequently, the certificates) are subject to partial or full redemption under
the circumstances described below. The pass through trustee will establish and
maintain with itself, on behalf of and for the benefit of the certificate
holders, one or more non-interest bearing accounts, each a special payments
account, for the deposit of special payments. Under the pass through trust
agreement, the pass through trustee must immediately deposit any special
payments received in the special payment account.
The pass through trustee will distribute the special payment to certificate
holders of record on the second day of the next month after which the pass
through trustee has received the special payment and given notice as required
under the pass through trust agreement, unless the special payment results from
the redemption of lessor notes. If the special payment results from the
redemption of lessor notes, the pass through trustee will distribute the special
payment on the date the redemption is scheduled to occur under the terms of the
applicable indenture. We refer to these dates as the special distribution dates,
in each case, so long as payment is received by the pass through trustee by
11:00 a.m., New York time, on such special distribution date. The pass through
trustee must give 20 days' notice to the certificate holders of any special
payments resulting from such a prepayment. The pass through trustee will mail
notice of each special payment to the certificate holders of record and, upon
request, certificate owners, and describe, among other things, the special
distribution date, the record date, the amount of the special payment per $1,000
of face amount of certificates and the allocation of principal, premium, if any,
and interest, if calculable and the reason for the special payment. The record
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date for each distribution of a special payment on a special distribution date
will be the fifteenth day before the special distribution date.
Method of payment. The pass through trustee will make distributions from
the certificate account or the special payment account of the pass through trust
on a scheduled distribution date or a special distribution date by wire transfer
in immediately available funds to an account maintained by such certificate
holder with a bank if DTC is the certificate holder of record, if a certificate
holder holds certificates in an aggregate amount greater than $10 million or if
any certificate holder that holds certificates in an aggregate amount greater
than $1 million requests that such distributions be made by wire transfer.
Otherwise, the pass through trustee will make distributions by check mailed to
each certificate holder of record on the applicable record date at its address
appearing on the register maintained by the pass through trustee. The pass
through trustee will make the final distribution for the pass through trust only
after surrender of the certificates at the office or agency of the pass through
trustee. The pass through trustee will mail notice of the final distribution (at
maturity, redemption or otherwise) to the certificate holders of record between
60 days and 20 days before the final distribution, specifying the date set for
such final distribution and the amount of such distribution.
If any scheduled distribution date or special distribution date is not a
business day, distributions scheduled to be made on such scheduled distribution
date or special distribution date may be made on the next succeeding business
day without any additional interest accruing during the intervening period.
REPORTS TO CERTIFICATE HOLDERS AND CERTIFICATE OWNERS
On each scheduled distribution date and special distribution date, the pass
through trustee will include with each distribution of a scheduled payment or
special payment a statement giving effect to such distribution to be made on the
distribution date, which sets forth the following information (per $1,000 in
aggregate principal certificate amount) to certificate holders of record and,
upon request, to a certificate owner:
(1) the amount of such distribution allocable to principal and the
amount allocable to premium, if any; and
(2) the amount of such distribution allocable to interest.
In addition, within a reasonable time after the end of each calendar year,
but not later than the last date permitted by law, the pass through trustee will
furnish to each person who at any time during such calendar year was a
certificate holder of record and, upon request, to each person who at any time
during such calendar year was a certificate owner, a statement specifying the
sum of the amounts determined above for such calendar year or, if such person
was a certificate holder of record or certificate owner during a portion of such
calendar year, for the applicable portion of such calendar year, and such other
items as are readily available to the pass through trustee and which a
certificate holder or certificate owner will reasonably request as necessary for
the purpose of such certificate holder's or certificate owner's preparation of
its federal income tax returns.
The pass through trustee will prepare these reports based on information
the DTC participants and the certificate owners supply to the pass through
trustee when the certificates are not issued in definitive form. The pass
through trustee will notify the certificate holders of all events of default
under the pass through trust agreement known to such pass through trustee within
90 days after the occurrence of such event of default. However, the pass through
trustee will be protected if it withholds notice from the certificate holders of
an event of default, other than a failure to pay principal of, premium, if any,
or interest on any lessor note, so long as the board of directors, the executive
committee or a trust committee of directors or specified responsible officers of
the pass through trustee determine in good faith that the withholding of such
notice is in the interests of the certificate holders and the certificate
owners.
At such time, if any, as certificates are issued in the form of definitive
certificates, the pass through trustee will prepare and deliver the information
described above to each certificate holder of record as the name and period of
record ownership of such certificate holder appears on the records of the
registrar of such certificates.
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We currently are not subject to the periodic reporting and other
informational requirements of the Exchange Act. However, we will be subject to
such reporting requirements during the fiscal year in which the exchange offer
registration statement or shelf registration statement is declared effective by
the SEC. In subsequent fiscal years, we may not be subject to the reporting
requirements of the Exchange Act. However, we currently have no intention to
stop filing such reports with the SEC.
We are required to furnish to the pass through trustee unaudited quarterly
and audited annual consolidated financial statements, with the accompanying
footnotes and report. The unaudited quarterly consolidated financial statements
will be furnished to the pass through trustee within 60 days following the end
of each of the first three fiscal quarters of each fiscal year. The audited
consolidated annual financial statements will be furnished to the pass through
trustee within 120 days following the end of each fiscal year commencing after
December 31, 2000. We will provide these financial statements for each of (1)
ourselves and our consolidated subsidiaries and (2) ourselves and our Core
Subsidiaries (excluding our Additional Subsidiaries). We will also furnish the
pass through trustee with notice of certain material events related to us. So
long as the certificates are not freely transferable under the Securities Act,
we will furnish the pass through trustee with any information required to be
delivered pursuant to Rule 144A(d)(4) under the Securities Act. We are also
required to furnish annually to the pass through trustee a statement as to the
fulfillment of our covenants and obligations under the pass through trust
agreement and the other lease documents.
The pass through trustee will, upon request (which may include a request to
receive such information for subsequent financial reporting periods on an
ongoing basis), furnish all such information directly to the applicable
certificate holders and certificate owners and to prospective purchasers of
certificates designated by such certificate holders or certificate owners.
VOTING OF LESSOR NOTES
The pass through trustee, as holder of the lessor notes in the pass through
trust, will have the right, under certain circumstances, to vote and give
consents and waivers in respect of those lessor notes. The pass through trust
agreement describes the circumstances under which the pass through trustee will
direct any action or cast any vote as the holder of such lessor notes at its own
discretion and the circumstances under which the pass through trustee will seek
instructions from the certificate holders. The principal amount of the lessor
notes held in the pass through trust directing any action or being voted for or
against any proposal will be in proportion to the principal amount of
certificates held by the certificate holders taking the corresponding position.
COVENANTS
So long as the certificates are outstanding, we will be subject to the
following covenants under the participation agreements:
Limitations on Restricted Payments. We will not, and will not permit any
of our Core Subsidiaries to, take any of the following actions, which we refer
to as Restricted Payments:
- declare or pay any dividend or make any other payment or distribution on
our account or the account of any of our Core Subsidiaries' equity
interests (including, without limitation, any payment in connection with
any merger or consolidation involving us or any of our Core Subsidiaries)
or to the direct or indirect holders of our or any of our Core
Subsidiaries' equity interests in their capacity as such; however, the
following dividends or distributions will not be considered Restricted
Payments:
(1) a dividend or distribution not in excess of $50 million on the
closing date;
(2) dividends or distributions payable in our equity interests or
equity interests of a Core Subsidiary (so long as it remains a Core
Subsidiary and our direct or indirect percentage ownership interest in a
Core Subsidiary is not reduced as a result of such dividend or
distribution);
(3) dividends or distributions to us or any Core Subsidiary; and
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(4) dividends or distributions to any shareholder of a Core Subsidiary
other than us or another Core Subsidiary, so long as the shareholder is a
Qualified Shareholder and the dividend or distribution is made pro rata to
each of the holders of the type of securities or other interests in respect
of which the dividend or distribution is being made, in each case, in
accordance with their respective holdings of the securities or other
interests in the Core Subsidiary making the dividend or distribution;
- purchase, redeem or otherwise acquire or retire for value (including,
without limitation, in connection with any merger or consolidation
involving us) any of our equity interests,
- make any payment on or with respect to, or purchase, redeem, defease or
otherwise acquire or retire for value any Indebtedness that is
subordinated to our obligations under the leases, or
- make any Restricted Investment;
unless, at the time of the Restricted Payment, each of the following conditions
is satisfied:
- we satisfy the following historical coverage ratio test for the most
recently ended four full fiscal quarters, or such shorter period (of not
less than one full fiscal quarter) commencing on the closing date and
ending on the last day of the most recent fiscal quarter for which
internal financial statements are available:
(1) if the four full fiscal quarters commencing with the quarter in
which the Restricted Payment is proposed to be made is a PPA Period, the
Cash Flow to Fixed Charges Ratio is equal to at least 1.5 to 1.0; or
(2) if the four full fiscal quarters commencing with the quarter in
which the Restricted Payment is proposed to be made is not a PPA Period,
the Cash Flow to Fixed Charges Ratio is equal to at least 1.7 to 1.0;
- we satisfy the following projected coverage ratio test for each of the
two following periods of four fiscal quarters commencing with the fiscal
quarter in which the Restricted Payment is proposed to be made:
(1) if the four full fiscal quarters commencing with the quarter in
which the Restricted Payment is proposed to be made is a PPA Period, the
projected Cash Flow to Fixed Charges Ratio is equal to at least 1.5 to 1.0;
or
(2) if the four full fiscal quarters commencing with the quarter in
which the Restricted Payment is proposed to be made is not a PPA Period,
the projected Cash Flow to Fixed Charges Ratio is equal to at least 1.7 to
1.0;
in each case, determined on a pro forma basis after giving effect to such
Restricted Payment and on a basis consistent with projections prepared by us in
good faith based upon assumptions consistent in all material respects with the
relevant contracts and agreements, historical operations, and our good faith
projections of future revenues and projections of operating and maintenance
expenses for us and the Core Subsidiaries in light of the then existing or
reasonably expected regulatory and market environments in the markets in which
the facilities or other assets owned by such person is or will be operated and
upon the assumption that there will be no early redemption or prepayment of
Indebtedness;
- we are then maintaining a fully undrawn (or, if previously drawn in whole
or in part, a fully reinstated) Rent Reserve Letter of Credit described
under the caption "-- Rent Reserve Letter of Credit" below;
- we have provided an officers' certificate to the indenture trustees and
the pass through trustee to the effect that the making of the Restricted
Payment will not have a material adverse effect on (a) our business,
assets, revenues, results of operations, financial condition or
prospects, or those of any of our Core Subsidiaries, taken as a whole,
(b) our ability to perform our obligations under the applicable lease
documents or (c) the validity or enforceability of the applicable lease
documents, the liens granted under the lease documents or the rights and
remedies under the lease documents; and
- no Significant Lease Default or Lease Event of Default has occurred and
is continuing.
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So long as no Significant Lease Default or Lease Event of Default has
occurred and is continuing or would be caused thereby, the preceding provisions
will not prohibit the redemption, repurchase, retirement, defeasance or other
acquisition of any of our subordinated Indebtedness or of any of our equity
interests in exchange for, or out of the net cash proceeds of the substantially
concurrent sale (other than to one of our subsidiaries) of, our equity
interests.
Sale of assets. Except in connection with a merger, consolidation or the
sale of all or substantially all of our properties or assets on the terms
described under the caption "-- Merger, consolidation or sale of substantially
all assets" below, we will not, and will not permit any of our Core Subsidiaries
to, sell, lease, transfer, convey or otherwise dispose of any assets, including
by way of the issue or sale by us or any of our Core Subsidiaries of equity
interests in our Core Subsidiaries or the designation of any Core Subsidiary as
an Additional Subsidiary, if the aggregate net book value of all asset sales
consummated since the closing date would exceed 15% of our Consolidated Tangible
Net Assets as of the beginning of our most recently ended full fiscal quarter.
Asset sales will be disregarded for purposes of the foregoing limitation if the
proceeds of the asset sales are invested by us or our Core Subsidiaries in a
permitted business or are used by us or any of our Core Subsidiaries to repay
any of our existing Indebtedness or any of our Core Subsidiaries' existing
Indebtedness or if the consideration received is retained by us or any of our
Core Subsidiaries.
The following asset sales will not be subject to the 15% limitation
described in the preceding paragraph:
- transfers of assets among us and any of our wholly-owned Core
Subsidiaries;
- sales of inventory (including fuel and coal), products or obsolete items
and other similar dispositions and sales of power in the ordinary course
of business;
- a transfer of ownership of the Kerr hydroelectric generating facility by
us or any Core Subsidiary to the Confederated Salish and Kootenai Tribes
or any successor in interest;
- sales of assets required to be made pursuant to any change in law,
regulation or any imposition by the FERC or any other governmental entity
having or claiming jurisdiction over us, our subsidiaries or the Montana
portfolio of any conditions or requirements;
- an issuance of equity interests by one of our wholly-owned Core
Subsidiaries to us or to another wholly-owned Core Subsidiary;
- a sale or liquidation of cash equivalents in the ordinary course of
business;
- a Restricted Payment that is made in cash or cash equivalents that is
permitted by the participation agreements; and
- Permitted Investments other than those made in Additional Subsidiaries
(unless made with proceeds described in clause (7) of the definition of
Permitted Investments).
Additionally, if after giving effect to any asset sale that otherwise would
cause the 15% limitation described above to be exceeded, Moody's and S&P
confirms the then current rating of the certificates, the asset sale will be
disregarded for purposes of the 15% limitation.
Merger, consolidation or sale of substantially all assets. We will not,
directly or indirectly, consolidate or merge with or into, any other person, or
sell, assign, convey, lease, transfer or otherwise dispose of all or
substantially all of our properties or assets (including equity interests of our
Core Subsidiaries) to any person or persons in one or a series of transactions,
unless immediately after giving effect to the transaction each of the following
conditions are satisfied:
- no Significant Lease Default or Lease Event of Default has occurred and
is continuing;
- the surviving entity, if other than us, will be organized under the laws
of the United States, any state thereof or the District of Columbia and
will assume all of our obligations under the lease documents;
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- we provide to the pass through trustee, the indenture trustees, the owner
lessors, the owner lessors' managers and the owner investors a customary
officers' certificate and customary legal opinions addressing certain
matters in connection therewith;
- if at the time of such consolidation or merger, the entity with whom we
have consolidated or merged has any Indebtedness, we would be permitted
to incur such Indebtedness under the caption "-- Limitation on incurrence
of Indebtedness" herein after giving effect to such consolidation or
merger; and
- unless we are the surviving entity, Moody's and S&P confirms the then
current rating of the certificates after giving effect to such
consolidation, merger or sale of all or substantially all of our assets.
In addition, unless the resulting or surviving entity shall be rated at
least investment grade, no consolidation, merger or sale, assignment, lease,
transfer or other disposition of all or substantially all of our property or
assets may be consummated without the consent of the owner investor.
Restriction on liens. We will not, nor will we permit any of our Core
Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or
become effective any liens on our or any of our Core Subsidiaries' properties or
assets now owned or hereafter acquired, except for the following permitted
liens:
- liens in existence on the closing date, including liens and encumbrances
identified on the policy of title insurance issued in connection with the
lease transactions;
- liens by us to any of our wholly owned Core Subsidiaries or by one of our
wholly owned Core Subsidiaries to us or any of our other wholly owned
Core Subsidiaries;
- any lien arising by reason of any judgment, decree or order of any court
so long as such lien is being contested in good faith and is
appropriately bonded or reserved against, and any appropriate legal
proceedings that may have been duly initiated for the review of such
judgment, decree or order have not been finally terminated or the period
within which such proceedings may be initiated has not expired;
- liens arising by reason of taxes, duties, assessments, imposts or other
governmental charges that are not yet delinquent or are being contested
in good faith;
- liens arising by reason of security for payment of worker's compensation
or other insurance;
- liens arising by operation of law in favor of carriers, warehousemen,
landlords, mechanics, materialmen, laborers or employees incurred in the
ordinary course of business for sums that are not yet delinquent or are
being contested in good faith;
- liens in favor of suppliers incurred in the ordinary course of business
for sums that are not yet delinquent or are being contested in good
faith;
- liens arising by reason of easements, rights-of-way, zoning and similar
covenants and restrictions or similar encumbrances or title defects that
do not in the aggregate materially interfere with the ordinary course of
our business or the business of our Core Subsidiaries;
- liens arising by operation of law pursuant to any license issued by the
FERC required for our operation of hydroelectric generation facilities;
- liens to secure the refinancing of previously secured permitted
Indebtedness, so long as the liens do not cover assets, as a whole, more
valuable than the assets covered by liens that secured the refinanced
Indebtedness;
- liens against earned receivables pledged to secure Indebtedness permitted
to be incurred pursuant to the covenant described under the caption
"-- Limitation on incurrence of Indebtedness" below;
- the interests of us, the owner investors, the owner lessors, the owner
lessors' managers, the indenture trustees and the pass through trustee
under any of the applicable lease documents;
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- liens caused by the owner lessors, the owner investors and the indenture
trustees that such parties are responsible for removing;
- our reversionary interests in the Colstrip facility site;
- liens to secure permitted Indebtedness described below under the caption
"-- Limitation on incurrence of Indebtedness,"other than subordinated
Indebtedness, so long as the liens will not secure Indebtedness in an
amount in excess of $25 million;
- liens on assets of any Additional Subsidiary that secure Non-Recourse
Indebtedness of such Additional Subsidiary; and
- the Colstrip units 1 and 2 ownership and operating agreements, the
Colstrip units 3 and 4 ownership and operating agreement and the common
facilities agreement or such other similar arrangements with respect to
the Colstrip facility and the Colstrip common facilities used or useful
to us or our Core Subsidiaries which could not reasonably be expected to
have a material adverse effect on (a) our business, assets, revenues,
results of operations, financial condition or prospects, or those of any
of our Core Subsidiaries, taken as a whole, (b) our ability to perform
our obligations under the applicable lease documents or (c) the validity
or enforceability of the applicable lease documents, the liens granted
under the lease documents or the rights and remedies under the lease
documents.
Limitation on incurrence of Indebtedness. We will not, and will not permit
any of our subsidiaries to, incur any Indebtedness unless, at the time of
incurrence of the Indebtedness, each of the following conditions is satisfied:
(1) we satisfy the following historical coverage ratio test for the
most recently ended four full fiscal quarters, taken as a whole, or shorter
period (of not less than one full fiscal quarter) commencing on the closing
date, each ending on the last day of the most recent fiscal quarter for
which internal financial statements are available:
(A) if the most recently ended four full fiscal quarters (or
shorter period of not less than one full fiscal quarter) was a PPA
Period, the Cash Flow to Fixed Charges Ratio shall equal at least 2.0 to
1.0; or
(B) if the most recently ended four full fiscal quarters is not a
PPA Period, the Cash Flow to Fixed Charges Ratio shall equal at least
2.5 to 1.0; and
(2) we satisfy the following projected coverage ratio test for each
calendar year during the term in which such new Indebtedness is
outstanding;
(A) if such calendar year is a PPA Period, the projected Cash Flow
to Fixed Charges Ratio shall equal at least 2.0 to 1.0, and
(B) if such calendar year is not a PPA Period, the projected Cash
Flow to Fixed Charges Ratio shall equal at least 2.5 to 1.0,
in each case, determined on a basis consistent with projections prepared by us
in good faith based upon assumptions consistent in all material respects with
the relevant contracts and agreements, historical operations, and our good faith
projections of future revenues and projections of operating and maintenance
expenses for us and the Core Subsidiaries in light of the then existing or
reasonably expected regulatory and market environments in the markets in which
the facilities or other assets owned by such person is or will be operated and
upon the assumption that there will be no early redemption or prepayment of
Indebtedness (other than early redemptions or prepayments of Indebtedness that
are to occur concurrently with the incurrence of such new Indebtedness); and
(3) in the case of Indebtedness incurred by any Core Subsidiary,
Moody's and S&P shall have confirmed the then current rating of the
certificates.
However, if a Significant Lease Default or Lease Event of Default has
occurred and is continuing, we will not be permitted to incur any Indebtedness,
unless the incurrence of Indebtedness would otherwise satisfy the
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requirements set forth in clauses (1) and (2) above and the application of the
proceeds therefrom will cure the Significant Lease Default or Lease Event of
Default. Each calculation made under clause (2) above will be made, as
applicable, after giving pro forma effect to the Indebtedness to be incurred,
the application of the proceeds of the Indebtedness, any Restricted Payments to
be made and any assets or businesses to be acquired in connection with the
incurrence of the Indebtedness, and to the consummation of any related
transactions.
Notwithstanding the foregoing, we and our subsidiaries, in the aggregate,
will be permitted to incur the following types of Indebtedness at any time:
(a) Indebtedness in respect of letters of credit, surety bonds or
performance bonds issued in the ordinary course of business;
(b) Indebtedness in an aggregate amount up to $45 million incurred in
connection with the issuance of the Rent Reserve Letters of Credit;
(c) Indebtedness of up to $50 million in the aggregate for general
corporate purposes incurred under our current working capital facility or
any replacement, successor, or additional working capital facility on
customary terms and conditions;
(d) Indebtedness of up to $25 million incurred for the purpose of
financing all or any part of the cost of the construction, installation,
lease, development or improvement of any assets used or useful in a
permitted business or for general corporate purposes;
(e) Indebtedness that is expressly subordinated to our payment
obligations under the leases and the other lease documents;
(f) Non-Recourse Indebtedness incurred by Additional Subsidiaries;
however, if the Indebtedness ceases to be Non-Recourse Indebtedness of an
Additional Subsidiary, it will not be permitted under this category of
permitted Indebtedness; and
(g) Indebtedness ("New Indebtedness") incurred in exchange for, or the
net proceeds of which are used to refund, refinance or replace Indebtedness
that we were permitted to incur under the participation agreements ("Old
Indebtedness"), so long as (A) the principal amount of the New Indebtedness
will not exceed the principal amount of the Old Indebtedness plus a
reasonable premium in connection with the redemption or repurchase of the
Old Indebtedness, (B) for each calendar year during the period in which the
Old Indebtedness would have been outstanding, the projected Cash Flow to
Fixed Charges Ratio (determined on a pro forma basis after giving effect to
the incurrence of such New Indebtedness and the retirement of the Old
Indebtedness) is at least equal to the then existing projected Cash Flow to
Fixed Charges Ratio, and (C) for each calendar year during the period in
which the New Indebtedness will be outstanding and the Old Indebtedness
would not have been outstanding,
(i) if such calendar year is a PPA Period, the projected Cash Flow to
Fixed Charges Ratio is equal at least 2.0 to 1.0; and
(ii) if such calendar year is not a PPA Period, the projected Cash
Flow to Fixed Charges Ratio is equal at least 2.5 to 1.0;
in each case, determined on a basis consistent with projections prepared by us
in good faith based upon assumptions consistent in all material respects with
the relevant contracts and agreements, historical operations, and our good faith
projections of future revenues and projections of operating and maintenance
expenses for us and the Core Subsidiaries in light of the then existing or
reasonably expected regulatory and market environments in the markets in which
the facilities or other assets owned by such person is or will be operated and
upon the assumption that there will be no early redemption or prepayment of
Indebtedness (other than Old Indebtedness).
Designation of Core Subsidiaries and Additional Subsidiaries. Our board of
managers may designate any Core Subsidiary to be an Additional Subsidiary if
that designation would not cause a Significant Lease Default or a Lease Event of
Default. The designation of a Core Subsidiary as an Additional Subsidiary will
be deemed to be an asset sale and will be subject to the provisions described
above under the caption "-- Sale of
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assets." If a Core Subsidiary is designated as an Additional Subsidiary, the
aggregate fair market value of all outstanding Investments owned by us and our
Core Subsidiaries in the subsidiary so designated will be deemed to be an
Investment made as of the time of the designation and will be subject to the
limitations set forth above under the caption "-- Limitations on Restricted
Payments." That designation will be permitted only if the resulting Investment
would be permitted at that time and if the Core Subsidiary otherwise meets the
definition of an Additional Subsidiary.
No subsidiary will be designated an Additional Subsidiary unless the
subsidiary:
(1) has no Indebtedness other than Non-Recourse Indebtedness;
(2) is not party to any agreement, contract, arrangement or
understanding with us or any Core Subsidiary, unless the terms of any such
agreement, contract, arrangement or understanding are no less favorable to
us or such Core Subsidiary than those that might be obtained at the time
from persons who are not affiliates of ours;
(3) is a person with respect to which neither we nor any of our Core
Subsidiaries has any direct or indirect obligation to (a) subscribe for
additional equity interests (unless the amount of such subscription could
be made as a Restricted Payment) or (b) maintain or preserve such person's
financial condition or to cause such person to achieve any specified levels
of operating results; and
(4) has not guaranteed or otherwise directly or indirectly provided
credit support for any Indebtedness of ours or of any Core Subsidiaries.
Any designation of one of our subsidiaries as an Additional Subsidiary will
be evidenced to the indenture trustees by filing with the indenture trustees a
certified copy of the board resolution giving effect to the designation and an
officers' certificate certifying that the designation complied with the
preceding conditions and was permitted by the covenant described above under the
caption "-- Limitation on Restricted Payments." If, at any time, any Additional
Subsidiary would fail to meet the requirements described in clauses (1) through
(4) above, it will cease to be an Additional Subsidiary for purposes of the
indentures and any Indebtedness of the subsidiary will be deemed to be incurred
by one of our Core Subsidiaries and, if the Indebtedness is not permitted to be
incurred under the covenant described above under the caption "-- Limitation on
Incurrence of Indebtedness," then we will be in default.
Our board of managers may at any time designate any Additional Subsidiary
to be a Core Subsidiary. The designation will be deemed to be an incurrence of
Indebtedness by one of our Core Subsidiaries in the amount of any outstanding
Indebtedness of the Additional Subsidiary, and will be permitted only if:
(a) the resulting Indebtedness is permitted under the covenant
described under the caption "-- Limitation on incurrence of Indebtedness"
above; and
(b) no Significant Lease Default or Lease Event of Default would be in
existence following the designation.
No Additional Subsidiary or person other than us and the Core Subsidiaries
may hold 50% or more of all voting and economic interests in any Core
Subsidiary.
Limitations on our activities. We will not be permitted, nor will we
permit any of our Core Subsidiaries, to engage in any business other than the
following permitted businesses:
- the generation, transmission, distribution, marketing and sale of power
from the Montana portfolio (and any expansions related to the Montana
portfolio or acquisitions of similar generating assets in Montana);
- activities related to the ownership and operation of the Rosebud Mine or
other coal assets in North America for the supply of fuel to the Montana
portfolio (and any expansions related to the Montana portfolio or
acquisitions of similar generating assets in Montana);
- all activities related or incidental to those described above; and
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- if Moody's and S&P confirm that the then existing ratings of the
certificates will not fall below an investment grade rating as a result
of our participation in such activities, any other activity related to
non-nuclear generation, transmission, distribution, marketing and sale of
power in North America.
Maintenance of Tax Status. We will not, and will not permit any of our
Core Subsidiaries to, voluntarily take any action which would cause us or our
Core Subsidiaries to become taxable as a separate entity for federal income tax
purposes.
Limitations on transactions with affiliates. We will not, nor will we
permit any of our Core Subsidiaries to, sell, lease, transfer or otherwise
dispose of any of our or its properties or assets to, or purchase any property
or assets from, or enter into or make or amend any contract, agreement,
understanding, loan, advance or guarantee with, to or for the benefit of, any
affiliate, unless the transaction or series of transactions is on terms that are
no less favorable to us or the Core Subsidiary than would be available in a
comparable transaction with an unrelated third party. This restriction will not
apply to transactions contemplated by any agreement entered into between us and
any of our affiliates as the same are in effect on the closing date.
Restrictions on guarantees. We will not, contingently or otherwise, be or
become liable, directly or indirectly, for any obligation guaranteeing in any
manner any Indebtedness or performance obligation of any other person, except
for the following permitted guarantees:
- endorsements and similar obligations in the ordinary course of business;
- guarantees existing on the closing date, and renewals of these guarantees
in the ordinary course of business;
- guarantees constituting Indebtedness that are permitted by the
participation agreements;
- performance guarantees not otherwise constituting Indebtedness in a
principal or notional amount that would be permitted to be incurred under
the participation agreements if the performance guarantees did constitute
Indebtedness;
- guarantees of Indebtedness that is permitted by the participation
agreements;
- guarantees of the performance of PPL EnergyPlus or any of our other
affiliates that has entered into an agreement with us or any Core
Subsidiary in the ordinary course of business in connection with (a)
sales or purchases of energy or capacity, (b) sales or purchases of
emissions credits, (c) fuel procurement or (d) ash waste disposal, in
each case related to a permitted business of ours or any Core Subsidiary
and not for speculative purposes;
- guarantees of the performance of any affiliate of ours that owns, leases
or operates the Rosebud Mine or other coal assets in North America that
supplies fuel to any permitted business, but only to the extent of our
ownership, leasehold or operating interest in the affiliate; and
- any other performance guarantee, so long as S&P and Moody's confirm that
the guarantee will not result in a downgrade of the then current ratings
of the certificates.
Nondiscrimination among leases. To the extent periodic rent or termination
value is due under more than one lease, payments will be made pro rata under all
of the leases without preference to any lease.
Rent Reserve Letter of Credit. We are required to maintain Rent Reserve
Letters of Credit for the benefit of each owner lessor. Each owner lessor, in
turn, will transfer its Rent Reserve Letter of Credit to the applicable
indenture trustee to secure payment on the lessor notes. Each Rent Reserve
Letter of Credit is required to have a drawing amount, as of its date of
issuance and as of each subsequent rent payment date (after giving effect to the
payment of the rent to be made on such rent payment date), equal to the greater
of (1) the next scheduled payment under the applicable lease or (2) 50% of the
next twelve months of the scheduled payments under the applicable lease. We may,
from time to time, replace any Rent Reserve Letter of Credit with a replacement
Rent Reserve Letter of Credit as long as there is no resulting interruption in
the coverage provided by the Rent Reserve Letter of Credit. We are required to
extend or replace each Rent Reserve Letter of Credit on or before the date that
is 60 days prior to its scheduled expiration date or any other
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early termination date if the Rent Reserve Letter of Credit has an expiration
date prior to the maturity date for the certificates. If at any time after the
issuance of a Rent Reserve Letter of Credit we become aware that the rating of a
financial institution which issued the Rent Reserve Letter of Credit falls below
the required level, then we are required to replace it with an alternative Rent
Reserve Letter of Credit within 60 days. If periodic rent or termination value
due under any lease is not paid when due, the applicable indenture trustee will
be instructed to draw on the applicable Rent Reserve Letter of Credit to the
extent necessary to remedy such failure to pay. If a Rent Reserve Letter of
Credit is drawn to pay periodic rent or termination value, we must provide a new
Rent Reserve Letter of Credit or reinstate the Rent Reserve Letter of Credit up
to the then required amount within 90 days.
Insurance. We and each of our Core Subsidiaries are required to maintain,
with financially sound and reputable insurance companies, insurance in such
amounts (with no greater risk retention) and against such risks as are
customarily maintained by companies of established repute engaged in the same or
similar businesses operating in the same or similar locations.
Special terms. Following are definitions of terms that we use in the
foregoing description of covenants.
"Additional Subsidiary" means a subsidiary of ours designated as an
Additional Subsidiary as described above under the caption "-- Designation of
Core Subsidiaries and Additional Subsidiaries."
"Cash Flow Available for Fixed Charges" for any period means, without
duplication:
(1) consolidated EBITDA of us and our Core Subsidiaries for such
period, minus
(2) the portion of such consolidated EBITDA described in the foregoing
clause (1) that is attributable to extraordinary gains or other
nonrecurring items included in EBITDA (other than to the extent such
extraordinary gains or nonrecurring items are offset by extraordinary
losses), minus
(3) for each Core Subsidiary having an interest holder other than us
or our Core Subsidiaries, the amount described in the foregoing clause (1)
attributable to such interests, plus
(4) EBITDA of any Additional Subsidiary and the proceeds from any
asset sales received by any Additional Subsidiary, in each case, to the
extent such amount is distributed to us or our Core Subsidiaries from such
Additional Subsidiary during such period, so long as the amount described
in this clause is not included in the calculation of the Cash Flow
Available for Fixed Charges for any projected period, minus
(5) capital expenditures made by us and our Core Subsidiaries during
such period other than capital expenditures financed with Indebtedness
permitted under the caption "-- Limitation on the incurrence of
Indebtedness" above.
"Cash Flow to Fixed Charges Ratio" means, with respect to any person for
any period, the ratio of (1) Cash Flow Available for Fixed Charges for such
period to (2) Fixed Charges for such period.
"Consolidated Tangible Net Assets" means, at any date of determination:
(1) our total net assets and the total net assets of us and our Core
Subsidiaries determined in accordance with GAAP, excluding, however, from
the determination of total net assets:
(a) goodwill, organizational expenses, research and product
development expenses, trademarks, tradenames, copyrights, patents,
patent applications, licenses and rights in any thereof, and other
similar intangibles;
(b) all deferred charges or unamortized debt discount and expenses;
(c) all reserves carried and not deducted from assets;
(d) securities which are not readily marketable;
(e) cash held in sinking or other analogous funds established for
the purpose of redemption, retirement or prepayment of capital stock or
other equity interests or Indebtedness;
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(f) any write-up in the book value of any assets resulting from a
revaluation thereof subsequent to the closing date; and
(g) any items not included in clauses (a) through (f) above which
are treated as intangibles in conformity with GAAP; plus
(2) the aggregate purchase price paid by the owner lessors for their
ownership interests in the leased assets, plus
(3) the aggregate net book value of all asset sales or dispositions
made by us or any of our Core Subsidiaries since the closing date to the
extent that the proceeds of the asset sales or dispositions or other
consideration received for the asset sales or dispositions are not invested
in any permitted business and are not retained by us or any of our Core
Subsidiaries, minus
(4) for each Core Subsidiary having an interest holder other than us
or any Core Subsidiary, the amount described in the foregoing clauses (1)
and (3) attributable to such interest.
"Core Subsidiary" means each of our subsidiaries other than an Additional
Subsidiary.
"EBITDA" means, with respect to any person for any period, the income (or
loss) before interest and taxes of such person, and, to the extent the following
items were included in determining such income (or loss):
- plus depreciation, amortization and other similar non-cash charges and
reserves;
- minus non-cash non-recurring income items, including extraordinary
non-cash gains (or losses);
- plus non-cash restructuring charges or other non-cash non-recurring
expense items and non-cash charges representing allocations from
affiliates;
- plus GAAP lease rent expense.
"Fixed Charges" means, with respect to us and our Core Subsidiaries for any
period, the sum, without duplication, of:
(1) the aggregate amount of interest expense with respect to
Indebtedness of such persons for such period, including (A) the net costs
under interest rate hedge agreements, (B) all capitalized interest (except
to the extent that such interest is either (x) not paid in cash or (y) if
paid in cash, is paid solely with the proceeds of the Indebtedness in
respect of which such interest accrued) and (C) the interest portion of any
deferred payment obligation;
(2) the aggregate amount of all mandatory scheduled payments (whether
designated as payments or prepayments) and sinking fund payments with
respect to principal of any Indebtedness of such persons; and
(3) the aggregate amount of all payments due under the leases, in each
case, scheduled to be paid by such person during such period.
"Indebtedness" of any person means:
(1) all indebtedness of such person for borrowed money;
(2) all obligations of such person evidenced by bonds, debentures,
notes or other similar instruments;
(3) all obligations of such person to pay the deferred purchase price
of property or services;
(4) all indebtedness created or arising under any conditional sale or
other title retention agreement with respect to property acquired by such
person (even though the rights and remedies of the seller or lender under
such agreement in the event of default are limited to repossession or sale
of such property);
(5) all Lease Obligations of such person;
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(6) all obligations, contingent or otherwise, of such person under
acceptance, letter of credit or similar facilities;
(7) all unconditional obligations of such person to purchase, redeem,
retire, defease or otherwise acquire for value any capital stock or other
equity interests of such person or any warrants, rights or options to
acquire such capital stock or other equity interests;
(8) all Indebtedness of any other person of the type referred to in
clauses (1) through (7) guaranteed by such person or for which such person
will otherwise (including under any keepwell, makewell or similar
arrangement) become directly or indirectly liable; and
(9) all third party Indebtedness of the type referred to in clauses
(1) through (7) above secured by (or for which the holder of such
Indebtedness has an existing right, contingent or otherwise, to be secured
by) any lien or security interest on property (including, without
limitation, accounts and contract rights) owned by the person whose
Indebtedness is being measured, even though such person has not assumed or
become liable for the payment of such third party Indebtedness. The amount
of such obligation is deemed to be the lesser of the value of such property
or the amount of the secured obligation.
"Investment" means with respect to any person, all direct or indirect
investments by that person in other persons (including affiliates) in the forms
of loans (including guarantees or other obligations), advances or capital
contributions (excluding commission, travel and similar advances to officers and
employees made in the ordinary course of business), purchases or other
acquisitions for consideration of Indebtedness, equity interests or other
securities, together with all items that are or would be classified as
investments on a balance sheet prepared in accordance with GAAP.
If we or any of our Core Subsidiaries sells or otherwise disposes of any
equity interests of any of our direct or indirect Core Subsidiaries and, after
giving effect to any such sale or disposition, that person is no longer a Core
Subsidiary, we, or the Core Subsidiary, as the case may be, will be deemed to
have made an Investment on the date of the sale or disposition equal to the fair
market value of the equity interests of such Core Subsidiary.
The acquisition by us or any of our Core Subsidiaries of a person that
holds an Investment in a third person will be deemed to be an Investment by us
or the Core Subsidiary in the third person in an amount equal to the fair market
value of the Investment held by the acquired person in the third person.
"Lease Obligations" means, without duplication, (1) indebtedness
represented by obligations under a lease that is required to be capitalized for
financial reporting purposes and (2) with respect to noncapital leases of
electric generating facilities (a) non-recourse indebtedness of the lessor in
such a lease, or (b) if the amount is indeterminable, then the present value,
determined using a discount rate equal to the incremental borrowing rate (as
defined in SFAS 13) of the lessee under such a lease, of rent obligations under
the lease.
"Non-Recourse Indebtedness" means Indebtedness:
(1) as to which neither we nor any of our Core Subsidiaries (a)
provides credit support of any kind (including any undertaking, agreement
or instrument that would constitute Indebtedness), (b) is directly or
indirectly liable as a guarantor or otherwise, or (c) is the lender;
(2) which, if in default, would not permit (upon notice, lapse of time
or both) any holder (as such) of any other Indebtedness of ours or any of
our Core Subsidiaries to declare a default on the other Indebtedness, cause
the payment of the other Indebtedness to be accelerated or payable prior to
its stated maturity, or to take enforcement action against an Additional
Subsidiary; and
(3) as to which the lenders have been notified in writing that they
will not have any recourse to our stock or assets or the stock or assets of
any of our Core Subsidiaries.
"Permitted Investment" means:
(1) any Investment in us or in one of our Core Subsidiaries;
(2) any Investment in cash equivalents;
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(3) any Investment by us or any of our Core Subsidiaries in a person,
if as a result of the Investment:
(a) the person becomes a Core Subsidiary; or
(b) the person is merged, consolidated or amalgamated with or into,
or transfers or conveys substantially all of its assets to, or is
liquidated into, us or one of our wholly owned Core Subsidiaries;
(4) any acquisition of assets solely in exchange for the issuance of
our equity interests;
(5) hedging obligations entered into in the ordinary course of
business and not for speculative purposes;
(6) any investment made from the proceeds of capital contributions to,
or the issuance and sale of equity interests in, us not constituting
Indebtedness other than the proceeds of any capital contributions required
by the terms of our credit facility; and
(7) other Investments in any person (including any Additional
Subsidiary) having an aggregate fair market value (measured on the date the
Investment is made and without giving effect to subsequent changes in
value), when taken together with all other Investments of the kind
described in this clause (7) since the closing date not to exceed $30
million.
"PPA" means:
- an arm's length, executed, valid and binding agreement between us or any
Core Subsidiary and either:
(1) a third party purchaser whose long-term senior debt is rated no
less than Baa3 by Moody's and BBB- by S&P; or
(2) an affiliate of ours, so long as the affiliate has executed a
valid and binding agreement with a third party purchaser whose long-term
senior debt is rated no less than Baa3 by Moody's and BBB- by S&P with
substantially the same terms (other than pricing) as the affiliate's
agreement with us or the Core Subsidiary;
in each case, for the sale of electric energy or capacity by us or the Core
Subsidiary to the third party or affiliate; or
- - financial hedge agreements relating to energy or capacity pricing that are:
(1) supported by available energy or capacity of us and our Core
Subsidiaries; and
(2) with counterparties having long-term senior debt that is rated no
less than Baa3 by Moody's and BBB- by S&P.
"PPA Period" means any consecutive period of four full fiscal quarters (or
shorter period of not less than one full fiscal quarter that is equal to the
period being evaluated for purposes of determining whether such period is a PPA
Period) during which we and our Core Subsidiaries have committed to sell at a
scheduled or formula price (as opposed to pure spot market price) at least 50%
of our total projected energy sales (measured in MWh and, in the case of Core
Subsidiaries that are not directly or indirectly wholly owned by us, taking into
account only the portion of the projected energy sales as directly corresponds
to our direct or indirect ownership interest in the Core Subsidiary) (1) for the
consecutive period of four full fiscal quarters commencing on the first day of
the period being evaluated and (2) for the consecutive period of four full
fiscal quarters commencing on the one year anniversary of the period being
evaluated, in each case, under one or more PPAs.
"Qualified Shareholder" means a person who holds a minority interest in a
Core Subsidiary, so long as S&P and Moody's have confirmed that, at the time of
the person's acquisition of an interest in the Core Subsidiary, the acquisition
and any transactions related thereto did not result in a downgrade of the then
current ratings of the certificates.
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"Rent Reserve Letter of Credit" means an irrevocable unconditional stand-by
letter of credit issued by a financial institution whose long-term debt is rated
A3 or higher by Moody's and A- or higher by S&P. The applicable owner lessor
will be the initial beneficiary under any Rent Reserve Letter of Credit. Each
owner lessor will transfer its Rent Reserve Letter of Credit to the applicable
indenture trustee. Each Rent Reserve Letter of Credit will allow drawings by the
applicable beneficiary if (1) we fail to pay periodic rent or termination value
when due or (2) a Lease Event of Default has occurred and is continuing. Our
reimbursement obligation under any letter of credit will be a senior unsecured
obligation of ours.
"Restricted Investment" means any Investment other than a Permitted
Investment.
SIGNIFICANT LEASE DEFAULTS
"Significant Lease Default" means any of the following:
(1) a failure by us to pay periodic rent or termination value under a
lease;
(2) a failure by us to pay any other amounts due and payable under the
applicable lease documents (other than excepted payments) in excess of
$250,000 except to the extent such amounts are in dispute and have not been
established to be due and payable; and
(3) any event or circumstance which is a Lease Event of Default under
clause (5), (6), (7) or (10) of the definition of Lease Event of Default,
or any event or circumstance which is, or with the giving of notice or
passage of time will be a Lease Event of Default under clause (9) of the
definition of Lease Event of Default.
LEASE EVENTS OF DEFAULT
"Lease Event of Default" means any of the following:
(1) a failure by us to pay periodic rent or termination value when
due, and such failure continues unremedied after application of the
proceeds of any applicable Rent Reserve Letter of Credit for five business
days;
(2) a failure by us to make any other payment under the lease
documents relating to such lease (other than excepted payments unless the
applicable owner lessor shall have declared a default with respect thereto)
within 30 days after our receipt of written notice of such default from the
applicable owner investor, owner lessor, indenture trustee or the pass
through trustee;
(3) a failure by us to maintain or cause to be maintained insurance in
the amounts and on the terms required by the lease;
(4) a failure by us to perform any covenant set forth in a
participation agreement, an indenture, the pass through trust agreement or
any covenant set forth in any other lease document relating to the lease
(other than any covenant referred to in clauses (1), (2), (3), (5), (6) or
(7)), in any material respect and which continues unremedied for 30 days
after receipt by us of written notice thereof from the applicable owner
investor, owner lessor, indenture trustee or the pass through trustee;
however:
(a) if such condition cannot be remedied within such 30-day period,
then the period within which to remedy such condition will be extended
up to an additional 180 days, so long as we diligently pursue such
remedy and such condition is reasonably capable of being remedied within
such additional 180-day period;
(b) in the case of our failure to maintain the Colstrip units in
accordance with applicable laws, if, to the extent and for so long as a
test, challenge, appeal or proceeding will be prosecuted in good faith
by us, the failure by us to comply with such requirement will not
constitute a Lease Event of Default if such test, challenge, appeal or
proceeding will not involve any danger of (1) foreclosure, sale,
forfeiture or loss of, or imposition of a lien on, any part of the
leased assets or the impairment of the use, operation or maintenance of
the leased assets in any material respect, or (2) any criminal liability
being incurred by, or any material adverse effect on the interests of,
the applicable owner
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investor, owner lessor, or indenture trustee, or the pass through
trustee, including, without limitation, subjecting the applicable owner
investor or owner lessor to regulation as a public utility under
applicable law, and so long as such test, challenge, appeal or
proceeding to review will not extend beyond the date 36 months prior to
the scheduled expiration of the lease; and
(c) in the case of our failure to maintain the Colstrip units in
accordance with applicable laws, if the noncompliance is not of a type
that can be immediately remedied, the failure to comply will not be a
Lease Event of Default if we are taking all reasonable action to remedy
the noncompliance and if, and only if, the noncompliance will not
involve any danger described in clauses (1) or (2) of clause (b) above,
and so long as the noncompliance will not extend beyond the date 36
months prior to the scheduled expiration of the lease;
(5) a failure by us to perform or observe in all material respects (a)
the covenants described under the captions "-- Limitation on the incurrence
of Indebtedness," "-- Limitations on Restricted Payments," or "-- Merger,
consolidation or sale of substantially all assets," "-- Sale of assets" or
(b) if such failure is in respect of any borrowed money, the covenants
described under the caption "-- Restriction on liens";
(6) a failure by us (a) following a drawing on a Rent Reserve Letter
of Credit, to replace or cause such Rent Reserve Letter of Credit to be
reinstated to the full amount required under the caption "-- Rent Reserve
Letter of Credit" within 90 days following such drawing or (b) to perform
or observe the other covenants described under the caption "-- Rent Reserve
Letter of Credit";
(7) a failure by us to comply in all material respects with the
restrictions on assignment set forth under the caption "Description of the
lease documents -- Sublease and assignment";
(8) any representation or warranty of us set forth in the lease
documents relating to such lease (other than a Tax Representation) proves
to have been incorrect in any material respect when made and continues to
be material and unremedied for a period of 30 days after receipt by us of
written notice thereof from the applicable owner investor, owner lessor or
indenture trustee or either pass through trustee; however, if such
condition cannot be remedied within such 30-day period, then the period
within which to remedy such condition will be extended by an additional 120
days, so long as we diligently pursue such remedy and such condition is
reasonably capable of being remedied within such additional 120-day period;
(9) customary events of bankruptcy and insolvency, whether voluntary
or involuntary, with a grace period of 60 days for involuntary events;
(10) acceleration of our Indebtedness (excluding obligations under the
applicable lease documents or Non-Recourse Indebtedness) in excess of $75
million in the aggregate; and
(11) so long we are the lessee under such lease, the occurrence of a
Change of Control.
The leases do not contain general cross-default provisions and default
under a lease would not necessarily result in a default under the other leases.
"Change of Control" means the consummation of any transaction or series of
related transactions (including, without limitation, any merger or
consolidation) the result of which is that any person (other than (a) PPL
Corporation or any of its successors into which PPL Corporation has consolidated
or merged, (b) any person who comes to be a beneficial owner (as defined below)
directly or indirectly of more than 50% of the voting power of or economic
interest in PPL Corporation, or (c) any of PPL Corporation's direct or indirect
wholly owned subsidiaries), becomes the "beneficial owner" (as such term is
defined in Rule 13(d)(3) under the Exchange Act, except that a person will be
deemed to have "beneficial ownership" of all securities that such person has the
right to acquire, whether such right is currently exercisable or is exercisable
only upon the occurrence of a subsequent condition), directly or indirectly, of
more than 50% of the voting power of or economic interests in us; provided that
a Change of Control will be deemed not to have occurred if Moody's and S&P
confirm that the then existing ratings of the certificates will not be lowered
as a result of any of the foregoing events.
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If any of the events described in the definition of "Change of Control"
occurs, but such event is not deemed a Change of Control because Moody's and S&P
confirm that the then existing ratings of the certificates would not be lowered
as a result of such event, then immediately after such event, the definition of
"PPL Corporation" in the indentures will be amended by a supplemental indenture
(without consent of the holders of the certificates) to mean, the entity or
entities Moody's and S&P relied upon, if any, in confirming the then existing
ratings of the certificates.
In addition, if:
(a) any person becomes a beneficial owner directly or indirectly of
more than 50% of the voting power of or economic interest in PPL
Corporation or
(b) any event that is not described in the definition of "Change of
Control" occurs, pursuant to which PPL Corporation merges into or
consolidates with another entity and PPL Corporation is not the surviving
entity,
then, immediately after such event, the definition of "PPL Corporation" in the
indentures will be amended by a supplemental indenture (without consent of the
holders of the certificates) in the case of clause (a), to refer to the person
so acquiring more than 50% of the voting power of or economic interest in PPL
Corporation or, in the case of clause (b), to mean such surviving entity.
EVENTS OF DEFAULT AND RIGHTS UPON EVENTS OF DEFAULT
An event of default under the pass through trust agreement is defined as
the occurrence and continuance of an event of default under any of the
indentures, which we refer to in this prospectus as an Indenture Event of
Default. We describe the Indenture Events of Default under the caption
"DESCRIPTION OF THE LEASE DOCUMENTS -- INDENTURE EVENTS OF DEFAULT." Under the
indentures, the owner lessors have the right under certain circumstances to cure
Indenture Events of Default that result from the occurrence of a Lease Event of
Default. If the owner lessor chooses to exercise its cure right, the Indenture
Events of Default and consequently, the event of default under the pass through
trust agreement will be deemed to be cured.
The pass through trust agreement provides that, so long as an Indenture
Event of Default has occurred and is continuing:
(1) the pass through trustee may, and upon the direction of the
certificate holders evidencing fractional undivided interests aggregating
not less than a majority in interest of the pass through trust, which we
refer to as the majority certificate holders, will, vote in favor of
directing the applicable indenture trustee to declare the unpaid principal
amount of such lessor notes then outstanding and any accrued and unpaid
interest thereon to be due and payable;
(2) the pass through trustee may, and upon the direction of the
majority certificates holders, will, vote to direct the applicable
indenture trustee regarding the exercise of remedies provided in the
indentures and consistent with the terms of the indenture.
Each indenture provides that so long as an Indenture Event of Default has
occurred and is continuing:
(a) the applicable indenture trustee may, and upon the instruction of
the holders of a majority of the aggregate outstanding principal amount of
the lessor note, will, declare the unpaid principal of and accrued interest
on the lessor note issued under the indenture to be due and payable; and
(b) the holders of a majority in aggregate outstanding principal
amount of the lessor note may direct the indenture trustee with respect to
the exercise of remedies under the indenture.
As an additional remedy, if an Indenture Event of Default has occurred and
is continuing, the pass through trust agreement provides that the pass through
trustee may, and upon the direction of the majority certificate holders must,
sell all or part of the lessor notes that are held in the pass through trust to
any person. In addition, if an owner lessor elects to purchase or redeem its
lessor note upon the occurrence and during the continuation of an Indenture
Event of Default, the pass through trustee will sell the lessor note to the
owner lessor at a price equal to the unpaid principal amount of the lessor note,
together with accrued but unpaid
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interest on the lessor note, but without any premium. Any proceeds received by
the pass through trustee upon any such sale will be deposited in the special
payment account and will be distributed to the certificate holders on a special
distribution date. The market for lessor notes in default may be very limited
and we cannot assure that they could be sold for a reasonable price. If the pass
through trustee sells any lessor note with respect to which an Indenture Event
of Default exists for less than the outstanding principal amount of the lessor
note, the certificate holders will receive a smaller amount of principal
distributions than anticipated and will not have any claim for the shortfall
against us, the owner lessors, the indenture trustees or the pass through
trustee.
Any amount distributed to the pass through trustee by an indenture trustee
on account of a lessor note following an Indenture Event of Default will be
deposited in the special payment account and will be distributed to the
certificate holders on a special distribution date as described under the
caption "-- Special payments." In addition, if following an Indenture Event of
Default, the related owner lessor or owner investor exercises its option to
purchase the lessor note issued by such owner lessor, the purchase price paid by
such owner lessor or owner investor to the pass through trustee for such lessor
note will be deposited in the special payment account and will be distributed to
the certificate holders on a special distribution date.
Any funds representing payments received with respect to any lessor note in
default, or the proceeds from the sale by the pass through trustee of any lessor
note in the special payment account will, to the extent practicable, be invested
by the pass through trustee in Permitted Government Investments (as defined
below) pending the distribution of such funds on a special distribution date.
The pass through trustee is prohibited from selling any Permitted Government
Investment prior to its maturity and no liability with respect to any such
investment other than by reason of its willful misconduct or negligence.
"Permitted Government Investments" mean obligations of the United States
maturing in not more than 60 days or such lesser time as is required for the
distribution of any such funds on a special distribution date.
The pass through trust agreement provides that the pass through trustee
will, within 90 days after the occurrence of a default (as defined below) in
respect of the pass through trust, give to the certificate holders notice,
transmitted by mail, of all uncured or unwaived defaults under the pass through
trust agreement actually known to a responsible officer of the pass through
trustee. However, except in the case of a default in the payment of principal
of, premium, if any, or interest on any of the lessor notes, the pass through
trustee will be protected in withholding notice if it in good faith determines
that the withholding of notice is in the interests of the certificate holders.
The term "default," for the purpose of the provision described in this paragraph
only, will mean the occurrence of any event of default under the pass through
trust agreement, except that in determining whether any event of default has
occurred, any applicable grace period or notice will be disregarded.
The pass through trust agreement contains a provision entitling the pass
through trustee to be indemnified by the certificate holders before proceeding
to exercise any right or power under the pass through trust agreement at the
request of the certificate holders, subject to the duty of the pass through
trustee during a default to act with the required standard of care.
In certain cases, the majority certificate holders may, on behalf of all
certificate holders, waive any past default or event of default and its
consequences under the pass through trust agreement and thereby annul any
direction given by such holders to the indenture trustee in this respect, except
for the following:
(1) a default in the deposit of any scheduled payment or special
payment or in the distribution of any such payment;
(2) a default in payment of the principal of, premium, if any, or
interest on, any of the lessor notes; or
(3) a default in respect of any covenant or provision of the pass
through trust agreement that cannot be modified or amended without the
consent of each certificate holder affected thereby.
The indentures provide that the holders of a majority in aggregate unpaid
principal amount of the lessor notes may on behalf of all holders waive any past
default or Indenture Event of Default, except for a default
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(a) in the payment of the principal of, premium, if any, or interest on any
lessor note or (b) a default in respect to provision of the indenture that
cannot be modified or amended without the consent of each holder of the lessor
notes.
MODIFICATION OF THE PASS THROUGH TRUST AGREEMENT
The pass through trust agreement will contain provisions permitting us and
the pass through trustee to enter into a supplemental trust agreement, without
the consent of any certificate holders, among other things:
(1) to evidence the succession of another corporation to us and the
assumption by any such successor corporation of our obligations under the
pass through trust agreement;
(2) to add to our covenants for the protection of the certificate
holders or to surrender any of our rights or powers;
(3) to cure any ambiguity in, or to correct or supplement any
defective or inconsistent provision of, the pass through trust agreement or
any supplemental trust agreement, or to make such provisions with respect
to matters or questions arising under the pass through trust agreement as
may be necessary or desirable, so long as such actions will not adversely
affect the interests of the certificate holders;
(4) to comply with requirements of the SEC, any applicable law, rules
or regulations of any exchange or quotation system on which the
certificates are listed, or any regulatory body;
(5) to modify, eliminate or add to the provisions of the pass through
trust agreement to such extent as will be necessary to qualify or continue
the qualification of the pass through trust agreement (including any
supplement thereto) under the Trust Indenture Act of 1939, or similar
federal stature enacted after the closing date, and to add to the indenture
such other provisions as may be expressly permitted by the Trust Indenture
Act;
(6) to add, eliminate or change any provision of the pass through
trust agreement that will not adversely affect the interests of the
certificate holders; or
(7) if necessary in our opinion, to provide for the issuance of
exchange certificates.
The pass through trust agreement also will contain provisions permitting us
and the pass through trustee, with the consent of the majority certificate
holders to execute supplemental trust agreements adding provisions to or
changing or eliminating any of the provisions of the pass through trust
agreement or modifying the rights of the certificate holders, except that no
such supplemental trust agreement may, without the consent of each certificate
holder so affected, do any of the following:
(1) reduce in any manner the amount of, or delay the timing of, any
receipt by the pass through trustee of payments with respect to the lessor
notes held in the pass through trust, or distributions in respect of any
certificate, or make distributions payable in coin or currency other than
that provided for in the certificates, or impair the right of any
certificate holder to institute suit for the enforcement of any such
payment when due;
(2) permit the disposition of any lessor note, permit the creation of
a lien on the pass through trust or otherwise deprive any certificate
holder of the benefit of ownership of the lessor note, except as provided
in the pass through trust agreement; or
(3) reduce the percentage of the aggregate interest of the pass
through trust that is required to approve any supplemental trust agreement
or reduce the percentage required for any waiver provided for in the pass
through trust agreement.
Notwithstanding the foregoing, we may not enter into a supplement to the
past through trust agreement unless we deliver an opinion of counsel confirming
that such supplemental agreement does not cause the pass through trust to become
taxable as an "association" within the meaning of Treasury Regulation Section
301.7701-4 or to be taxable as other than a pass through entity for federal
income tax purposes.
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TERMINATION OF THE PASS THROUGH TRUST
Both our obligations and those of the pass through trustee created by the
pass through trust agreement, and the pass through trust, will terminate upon
the distribution to certificate holders of all amounts required to be
distributed to them pursuant to the pass through trust agreement and the
disposition of all property held in the pass through trust. The pass through
trustee will mail to each certificate holder of record notice of the termination
of the pass through trust, the amount of the proposed final payment and the
proposed date for the distribution of such final payment for the pass through
trust. The final distribution to any certificate holder will be made only upon
surrender of such certificate holder's certificates at the office or agency of
the pass through trustee specified in such notice of termination.
THE PASS THROUGH TRUSTEE
The Chase Manhattan Bank is the pass through trustee for the pass through
trust. The pass through trustee and any of its affiliates may hold certificates
in their own names. The pass through trustee makes no representations as to the
validity or sufficiency of the pass through trust agreement, the certificates,
the lessor notes, the indentures, the leases or other lease documents. The Chase
Manhattan Bank is also the indenture trustee for the lessor notes issued under
the indentures.
The pass through trustee may resign at any time, in which event we will be
obligated to appoint a successor trustee. The certificate holders holding a
majority in interest of the certificates may remove the pass through trustee at
any time by notice to the pass through trustee, us, the owner lessor and lease
indenture trustee. If the pass through trustee ceases to be eligible to continue
as such under the pass through trust agreement ceases to comply with certain
provisions of the Trust Indenture Act at any time it is required to do so
following notice or becomes incapacitated or insolvent, we (or the owner lessor
if a Lease Event of Default has occurred) may remove the pass through trustee,
or any certificate holder which has held such certificate for at least six
months may, on behalf of himself and all others similarly situated, petition any
court of competent jurisdiction for the removal of the pass through trustee and
the appointment of a successor trustee. Any resignation or removal of the pass
through trustee and appointment of a successor trustee for the pass through
trust does not become effective until acceptance of the appointment by the
successor trustee.
The pass through trust agreement provides that we will pay the pass through
trustee's fees and expenses. In addition, with certain exceptions, we will also
indemnify the pass through trustee for any loss, liability or expense arising
out of or in connection with the acceptance or administration of the pass
through trust.
BOOK-ENTRY; DELIVERY AND FORM
All payments made by us under the leases to the indenture trustees (as
assignees of the owner lessors) and by the indenture trustees to the pass
through trustee will be in immediately available funds and delivered through DTC
in immediately available funds.
Secondary trading in long-term notes and debentures of corporate issuers
generally is settled in clearinghouse or next-day funds. In contrast, secondary
trading in pass through certificates (such as the certificates offered hereby)
generally is settled in immediately available funds. The certificates will trade
in DTC's Same-Day Funds Settlement System until maturity, and secondary market
trading activity in such certificates will therefore be required by DTC to
settle in immediately available funds. No assurance can be given as to the
effect, if any, of settlement in immediately available funds on trading activity
in the certificates.
DTC has advised us as follows: DTC is a limited purpose company organized
under the laws of the State of New York, a "banking organization" within the
meaning of the New York Banking Law, a member of the Federal Reserve System, a
"clearing corporation" within the meaning of the Uniform Commercial Code and a
"Clearing Agency" registered pursuant to the provision of Section 17A of the
Exchange Act. DTC was created to hold securities for its participants and
facilitate the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its
participants, thereby eliminating the need for physical movement of
certificates. Participants include securities brokers and dealers, banks, trust
companies and clearing corporations and certain other organizations. Indirect
access to
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the DTC system is available to others such as banks, brokers, dealers and trust
companies that clear through or maintain a custodial relationship with a
participant, either directly or indirectly ("indirect participants").
So long as DTC or its nominee is the registered owner or holder of the
Global Certificates, DTC or such nominee, as the case may be, will be considered
the sole record owner or holder of the certificates represented by such Global
Certificates for all purposes under the related pass through trust agreement. No
beneficial owners of an interest in the Global Certificates will be able to
transfer that interest except in accordance with DTC's applicable procedures, in
addition to those provided for under the pass through trust agreement and, if
applicable, Euroclear or Clearstream.
Payments of the principal of, premium, if any, and interest on the Global
Certificates will be made to DTC or its nominee, as the case may be, as the
registered owner thereof. Neither us, the pass through trustee, nor any paying
agent will have any responsibility or liability for any aspect of the records
relating to or payments made on account of beneficial ownership interests in the
Global Certificates or for maintaining, supervising or reviewing any records
relating to such beneficial ownership interests.
We expect that DTC or its nominee, upon receipt of any payment of
principal, premium, if any, or interest in respect of the Global Certificates
will credit participants' accounts with payments in amounts proportionate to
their respective beneficial ownership interests in the principal amount of such
Global Certificates, as shown on the records of DTC or its nominee. We also
expect that payments by participants to owners of beneficial interests in such
Global Certificates held through such participants will be governed by standing
instructions and customary practices, as is now the case with securities held
for the accounts of customers registered in the names of nominees for such
customers. Such payments will be the responsibility of such participants.
Neither us, nor the pass through trustee will have any responsibility for
the performance by DTC or its participants or indirect participants of their
respective obligations under the rules and procedures governing their
operations.
If DTC is at any time unwilling or unable to continue as a depositary for
the Global Certificates and a successor depositary is not appointed by us within
90 days, the pass through trust will issue definitive certificates in exchange
for the Global Certificates.
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DESCRIPTION OF THE LEASE DOCUMENTS
THE LESSOR NOTES
General. The lessor notes were issued a single series (or tranche) under
the indentures between each owner lessor and The Chase Manhattan Bank, as
indenture trustee.
Payments of interest and principal. The owner lessor must pay interest on
the unpaid principal amount of the lessor notes on each scheduled distribution
date at the rate per annum indicated on the cover page of this prospectus
calculated on the basis of a 360-day year of twelve 30-day months, until the
final distribution date. Any interest payment on a lessor note will result in a
corresponding distribution on the certificates.
The initial aggregate principal amount of the lessor notes is $338 million.
There is a lessor note issued pursuant to each of the four lease indentures. The
initial principal amount of these four lessor notes is approximately
$146,237,000, $144,818,000, $23,587,000 and $23,358,000. Each lessor note is
scheduled to amortize in accordance with the percentage amortization set forth
in the table below. The aggregate scheduled payments of principal on the lessor
notes are also shown in the table below. Any principal payment on a lessor note
will result in a corresponding distribution on the certificates.
PRINCIPAL PAYMENT PERCENTAGE SCHEDULED AGGREGATE SCHEDULED
DATES PRINCIPAL AMORTIZATION PRINCIPAL PAYMENT
----------------- ---------------------- -------------------
July 2, 2001 1.272781% $ 4,302,000
July 2, 2002 5.768047% $ 19,496,000
July 2, 2003 5.615680% $ 18,981,000
July 2, 2004 5.096746% $ 17,227,000
July 2, 2005 3.944675% $ 13,333,000
July 2, 2006 4.248225% $ 14,359,000
July 2, 2007 4.005030% $ 13,537,000
July 2, 2008 4.994083% $ 16,880,000
July 2, 2009 5.966568% $ 20,167,000
July 2, 2010 7.034911% $ 23,778,000
July 2, 2011 7.820710% $ 26,434,000
July 2, 2012 7.249704% $ 24,504,000
July 2, 2013 10.280473% $ 34,748,000
July 2, 2014 11.054438% $ 37,364,000
July 2, 2015 10.281361% $ 34,751,000
July 2, 2016 1.816272% $ 6,139,000
July 2, 2017 0.887574% $ 3,000,000
July 2, 2018 0.887574% $ 3,000,000
July 2, 2019 0.887574% $ 3,000,000
July 2, 2020 0.887574% $ 3,000,000
----------- ------------
100.000000% $338,000,000
The owner lessors have leased the leased assets and have subleased the
Colstrip facility site to us pursuant to the leases, and the site lease and
subleases. We are obligated to pay or cause to be paid rent and other payments
to the owner lessor under each lease in amounts that will be at least sufficient
to pay the principal of, premium, if any, and interest on the related lessor
notes when and as due and payable (except principal and interest payable upon an
Indenture Event of Default that is not caused by a Lease Event of Default and
except any premium payable by the owner lessors in connection with an early
termination of the leases). However, the lessor notes are not obligations of, or
guaranteed by us (except to the extent that we may, in certain circumstances
described herein, assume the obligations of the applicable owner lessor under
the lessor notes). Payments under each lease in excess of the amounts required
to make required payments on the applicable lessor notes will be paid by the
indenture trustee to the applicable owner lessor for distribution to the
applicable owner investor and will not be available for distribution to the
certificate holders except in certain
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cases upon the occurrence of an Indenture Event of Default. Our rental
obligations under the leases and the other lease documents are general
obligations of ours.
Security. The lessor notes issued by an owner lessor are secured by a lien
on and first priority security interest in its rights and interests in the
applicable collateral. The collateral includes (other than certain customary
excepted payments and excepted rights reserved to the owner lessor and the owner
investor) such owner lessor's interest in:
- the applicable interests in the leased assets;
- the applicable interests in the Colstrip facility site;
- the Colstrip units 1 and 2 ownership and operating agreements or the
Colstrip units 3 and 4 ownership and operating agreement;
- the common facilities agreement;
- the applicable lease and its rights arising under the lease, including
the right to receive payments of rent or elections under the lease;
- the applicable site lease and sublease and other lease documents (other
than the tax indemnity agreement) relating to the applicable leased
assets;
- any sublease of its leased assets subsequently entered into by us;
- the related Rent Reserve Letter of Credit;
- all rents, profits and other income of property subject to the applicable
lease indenture, including payments or proceeds of the sale of the
applicable leased assets;
- other property of the owner lessor pursuant to the transactions related
to the applicable lease; and
- the proceeds of all of the above.
We refer to the foregoing as the Collateral. The lessor note issued for any
lease transaction is not cross collateralized to the lessor note for any other
lease transaction.
So long as no Indenture Event of Default has occurred and is continuing
under its indenture, the applicable owner lessor will be entitled to exercise
all of the rights of such owner lessor under the applicable lease documents,
subject to certain specific exceptions (including with respect to amendments,
waivers, modifications and consents under specified provisions of certain of
such lease documents). The owner lessors' rights, however, will not include the
right to receive payments of rent and certain other amounts due under the
leases, which payments will be made directly to the applicable indenture
trustee. The assignment by each owner lessor to the applicable indenture trustee
of its rights under the related lease and other lease documents also will
exclude certain rights of such owner lessor, including rights relating to
indemnification by us for certain matters and insurance proceeds payable solely
to such owner lessor under liability insurance maintained by us under such
lease. For a description of certain other rights of the owner lessors, see "The
Leases -- Lease Events of Default."
Funds, if any, held from time to time by the indenture trustee pursuant to
the lease indentures will be invested by the indenture trustee, at the direction
and at the risk and expense of each owner lessor, in permitted investments. Each
owner lessor is required on demand to pay to the indenture trustee the amount of
any loss resulting from any such investment.
Limitation of liability. The lessor notes are not obligations of, or
guaranteed by us, the owner investors, or the owner lessors' manager. None of
the owner lessors' managers, the owner investors or the indenture trustee, or
any affiliates thereof, will be personally liable to any holder of a lessor note
or, in the case of the owner lessors' managers or any owner investor, to the
indenture trustee for any amounts payable under any lessor notes or, except as
provided in the applicable lease indenture, for any liability under such lease
indenture. All payments of principal of, premium, if any, and interest on the
lessor notes (other than payments made in connection with an optional redemption
or purchase by the applicable owner lessor or owner investor)
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will be made only from the assets subject to the lien of the related lease
indenture or the income and proceeds received by the indenture trustee therefrom
(including rent payable by us under the related lease).
Except as otherwise provided in the lease indenture, neither the owner
lessors nor the owner lessors' managers will be answerable or accountable under
any lease indenture or lessor notes under any circumstances except for: (1) its
own willful misconduct or gross negligence not caused by a breach of warranty,
covenant, or representation in any related lease document by us or any of our
affiliates, (2) misrepresentation or breach of warranty in any related lease
document or breach of covenant thereunder insofar as not attributable to a
breach of any covenant, representation or warranty by us or any of our
affiliates, contained in any related lease document, and (3) certain other
limited acts or omissions.
REDEMPTION OF LESSOR NOTES
Optional redemption. The owner lessors may redeem the lessor notes at the
principal amount thereof, together with interest accrued to and unpaid on the
date of redemption plus a make whole premium, if any, upon:
(1) an optional refinancing of all lessor notes at our request; or
(2) an optional prepayment by an owner lessor of the lessor note issued
under the applicable indenture, but only with our consent.
We will agree not to request that any lessor notes be refinanced and we
will agree not to consent to any optional prepayment by an owner lessor, unless
all lessor notes are being redeemed. In addition, we will not request an
optional refinancing of the lessor notes prior to the fifth anniversary of the
closing date without the owner investors' consent.
The make whole premium for any lessor note subject to redemption is an
amount equal to the discounted present value of such lessor note less the unpaid
principal amount of such lessor note; provided that the make whole premium will
not be less than zero. For purposes of this definition, the discounted present
value of any lessor note subject to redemption pursuant to any indenture will be
equal to the discounted present value of all principal and interest payments
scheduled to become due in respect of such lessor note after the date of such
redemption, calculated using a discount rate equal to the sum of (1) the yield
to maturity on the U.S. Treasury security having an average life equal to the
remaining average life of such lessor note and trading in the secondary market
at the price closest to par and (2) 50 basis points. However, if there is no
U.S. Treasury security having an average life equal to the remaining average
life of such lessor note, such discount rate will be calculated using a yield to
maturity interpolated or extrapolated on a straight-line basis (rounding to the
nearest calendar month, if necessary) from the yields to maturity for two U.S.
Treasury securities having average lives most closely corresponding to the
remaining life of such lessor note and trading in the secondary market at the
price closest to par.
Mandatory redemption with make whole premium. An owner lessor will redeem
its lessor note(s) (or the portion thereof relating to the affected Colstrip
unit(s)) at any time on or after the fifth anniversary of the closing date at
the principal amount of the lessor note(s) being redeemed, together with all
accrued and unpaid interest thereon, if any, to the redemption date, plus a make
whole premium (as defined above), if any, upon early termination of its lease(s)
in whole or in part with respect to such Colstrip unit(s) following a
determination in good faith by our board of directors that one or more of the
Colstrip unit or units are:
(1) economically or technologically obsolete (other than as a result
of (a) a change in law, regulation or tariff of general application or (b)
imposition by the FERC or any other governmental entity having or claiming
jurisdiction over us, or such Colstrip unit(s) of any conditions or
requirements (including, without limitation, requiring significant capital
improvements to such Colstrip unit(s)) upon the initial issuance, continued
effectiveness or renewal of any license or permit required for the
operation or ownership of such Colstrip unit(s); or
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(2) surplus to our needs or are no longer useful in our trade or
business (including without limitation, as a result of a change in the
markets for the wholesale purchase or sale of energy or any material
abrogation of power purchase agreements).
If one or two but less than all of the Colstrip units are determined
to be obsolete, surplus or no longer useful, then we may (a) terminate the
leases with respect to the affected Colstrip unit(s) and a proportionate
undivided interest in the common facilities, and (b) continue the leases
with respect to the unaffected Colstrip unit(s) and a proportionate
undivided interest in the common facilities. Notwithstanding the foregoing,
we may only terminate or partially terminate a lease with respect to any
Colstrip unit pursuant to the foregoing, if the other lease relating to
such unit is also terminated with respect to such Colstrip unit.
Prior to any such termination, we will deliver to the pass through
trustee an officers' certificate setting forth in reasonable detail the
basis on which we are exercising such termination right. The pass through
trustee will furnish, upon request, such officer's certificate to the
certificate holders and to the certificate owners.
If we elect to terminate or partially terminate the leases because one
or more of the Colstrip unit(s) are obsolete, surplus or no longer useful,
we will, at the request of any owner lessor, use commercially reasonable
efforts, as a non-exclusive agent for such owner lessor, to obtain bids and
sell such owner lessor's interest in such Colstrip unit(s) on the date such
lease terminates with respect to such Colstrip unit(s). All of the proceeds
of any such sale will be for the account of such owner lessors so long as,
to the extent the sales proceeds exceed the then applicable termination
value, such excess will be paid to the applicable indenture trustee and
used to pay the modified make whole premium due as a result of such
redemption. Neither us, any of our affiliates nor any third party with whom
we or any of our affiliates has an arrangement to use or operate the
affected Colstrip unit(s) to generate power for our benefit after
termination of the leases may be the purchaser of such interests.
Mandatory redemption without premium. An owner lessor will redeem its
lessor note(s) in whole or, in the case of clauses (1) and (2) below, in
part, at the principal amount of the lessor note(s) being redeemed,
together with all accrued and unpaid interest thereon, if any, to the
redemption date, but without any premium, upon receipt by the applicable
indenture trustee of any amount under any of the following circumstances:
(1) termination of the leases with respect to one or more of the
Colstrip units upon the occurrence of an Event of Loss as described below
under the caption "-- The leases -- Event of loss," with respect to such
unit(s) (unless we elect to rebuild or replace the damaged unit(s) or, in
the case of a Regulatory Event of Loss we acquire the applicable owner
lessor's interest in the leased assets and assume the lessor note(s) issued
under such indenture(s); so long as if we elect to rebuild or replace a
damaged unit, we make a similar election with respect to such unit under
the other lease relating to such unit);
(2) exercise by us of our right to terminate the leases with respect
to one or more of the Colstrip units following a determination in good
faith by our board of directors that such unit(s) are economically or
technologically obsolete, as a result of (a) a change in law, regulation or
tariff of general application or (b) imposition by the FERC or any other
governmental entity having or claiming jurisdiction over us, or such
unit(s) of any conditions or requirements (including, without limitation,
requiring significant capital improvements to such unit(s)) upon the
initial issuance, continued effectiveness, or renewal of any license or
permit required for the operation or ownership of such unit(s), provided,
that we may not terminate a lease with respect to any unit pursuant to this
clause (2), unless the other lease relating to such unit is also terminated
with respect to such unit; or
(3) exercise by us of our option to terminate one or more of leases
(except under circumstances in which we either purchase the applicable
owner lessor's interest in the applicable leased assets and assume
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its lessor note(s) or purchase the applicable owner investor's interest in
the related owner lessor and withdraw such termination notice) if:
(a) a change in law causes it to become illegal for us to
continue such lease(s) or to make payments thereunder and the other lease
documents related to such lease(s) and the transactions contemplated
thereby cannot be restructured to comply with such change in law; or
(b) one or more events outside of our control occurs that gives
rise to indemnity obligations under the lease documents, such obligations
can be avoided if such lease(s) are terminated and the owner lessors sell
their interests leased thereunder to us, and the present value of such
avoided payments would exceed 3% of the original purchase price of such
interest.
Prior to any termination under clause (2) above, we will deliver to the
pass through trustee an officer's certificate setting forth in reasonable detail
the basis on which we are exercising such termination right. The pass through
trustee will, upon request, furnish such officer's certificate to the
certificate holders and certificate owners. In the event of an early termination
under clause (2) above, we will, at the request of any owner lessor, use
commercially reasonable efforts, as non-exclusive agent for such owner lessor,
to obtain bids and sell such owner lessors' interests in such affected unit(s).
All of the proceeds of such sale will be for the account of such owner lessor
and none of such proceeds will be for our account. Neither us, any of our
affiliates and any third party with whom we, or any of our affiliates has an
arrangement to use or operate such unit(s) to generate power for our benefit
after the termination of the leases, may be the purchaser of such interests.
"Regulatory Event of Loss" means any event which subjects an owner
investor's interest in the leased assets to any rate of return regulation by any
governmental entity, or any event which subjects the owner investor or the owner
lessor to any other public utility regulation of any governmental entity or law
that in the reasonable opinion of the owner investor is burdensome, in either
case by reason of the participation of the owner lessor or the owner investor in
the transaction contemplated by this prospectus, and not, in any event, as a
result of:
(1) investments, loans or other business activities of the owner
investor or its affiliates in respect of equipment or facilities similar in
nature to the Colstrip facility or any part of the Colstrip facility or in
any other electrical, steam, cogeneration or other energy or utility
related equipment or facilities or the general business or other activities
of the owner investor or affiliates or the nature of any of the properties
or assets from time to time owned, leased, operated, managed or otherwise
used or made available for use by the owner investor or its affiliates; or
(2) a failure of the owner investor to perform routine, administrative
or ministerial actions the performance of which would not subject the owner
investor to any adverse consequence (in the reasonable opinion of the owner
investor acting in good faith).
We, the owner lessor and owner investor agree to cooperate and to take
reasonable measures to alleviate the source or consequence of any regulation
constituting a Regulatory Event of Loss at our cost and expense and so long as
there shall be no adverse consequences to the owner lessor or owner investor as
a result of such cooperation or the taking of reasonable measures.
Assumption by us of lessor notes. So long as no Significant Lease Default
or Lease Event of Default has occurred and is continuing, upon the termination
of a lease as a result of
(1) a Regulatory Event of Loss,
(2) a change in law that makes it illegal for us to continue such
lease or make payments under the lease and the other lease documents
related thereto, or
(3) us becoming obligated to pay an indemnity under the applicable
lease documents in an amount in excess of 3% of the present value of the
cost of the applicable interest in the leased assets, and,
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in each case, upon the purchase by us of the applicable owner lessor's interest
in the leased assets, we will have the option to (a) assume the related lessor
note on a fully recourse basis or (b) purchase the owner investor's interest in
the owner lessor and withdraw such termination notice.
As a condition to the assumption of any lessor notes, the indenture trustee
will receive an opinion of our counsel to the effect that, among other things:
- the assumption agreement and the applicable lessor notes constitute the
legal, valid and binding obligations of us, subject to certain
exceptions;
- the assumption agreement and the assumption of the lessor notes would not
cause a taxable transaction to occur as to any direct or indirect holder
of a lessor note (including any certificate owner); and
- the lien of the lease indenture will continue to be a first priority
perfected lien on the collateral.
In addition, S&P and Moody's will confirm that such assumption will not
result in a downgrade of the then existing credit rating of the certificates.
Indenture Events of Default. When we refer to an Indenture Event of
Default, we mean any of the following:
(1) a Lease Event of Default under the applicable lease, other than
with respect to:
- certain customary excepted payments reserved to the applicable
owner lessor and the owner investor; or
- our failure to maintain required insurance, if, and so long as,
(a) the insurance actually maintained by or on behalf of us
constitutes Prudent Industry Practice, and (b) the applicable
owner investor waives such Lease Event of Default;
(2) a payment default by the owner lessor under the applicable
indenture in respect of principal, premium, interest or any other amounts
due with respect to the lessor notes that continues unremedied for five
business days;
(3) failure by the owner lessor to perform any covenant set forth in
such indenture or failure of the owner lessor, the owner lessor's manager
or an owner investor to perform certain covenants under the participation
agreements or failure of the owner investor's parents to perform, any
material covenant under such owner investor's parent guaranty, in each case
in any material respect, which failure remains unremedied for a period of
30 days after written notice thereof; however, if capable of being
remedied, such period will be extended for up to 180 days, so long as such
party diligently pursues such remedy and such failure is reasonably capable
of being remedied within such period;
(4) any representation or warranty made by the owner investor, the
owner lessor or the owner lessor's manager, in the participation agreement
or in any officers' certificate delivered pursuant thereto or by the owner
investor's parents in its parent guaranty will prove at any time to have
been incorrect as of the date made in any material respect and will
continue to be material and unremedied for a period of 30 days after
receipt by such party of written notice thereof; however, if capable of
being remedied, such period will be extended for up to an additional 120
days, so long as such party diligently pursues such remedy and such
condition is reasonably capable of being remedied within such period; and
(5) customary events of bankruptcy and insolvency, whether voluntary
or involuntary, with respect to the owner lessor, the owner investor or its
parents, with a grace period of 60 days for involuntary events.
Remedies. Subject to certain rights of an owner lessor and the applicable
owner investor described below, if an Indenture Event of Default has occurred
and is continuing, the applicable indenture trustee may exercise certain
specified rights and remedies available to it under applicable law, including,
if a Lease Event of Default under the related lease has occurred and is
continuing, one or more of the remedies with respect to its security interest in
the leased assets and Colstrip facility site that are afforded by such lease for
Lease Events of Defaults. Such remedies may be exercised by the applicable
indenture trustee to the exclusion of the applicable owner lessor and the
applicable owner investor. A sale of the leased assets and Colstrip facility
site
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upon the exercise of such remedies will be free and clear of any rights of those
parties (other than, in certain cases, rights of redemption provided by law),
including our rights under such lease. No exercise of any remedies by such
indenture trustee, however, may affect our rights under such lease unless a
Lease Event of Default has occurred and is continuing thereunder.
Upon the occurrence of an Indenture Event of Default arising out of a Lease
Event of Default, no indenture trustee will be entitled to exercise any remedy
under the applicable indenture which could or would divest the owner lessor of
its ownership interest in any collateral subject thereto, unless such indenture
trustee, to the extent it is then entitled to do so under the lease documents
related thereto and is not then stayed or otherwise prevented from doing so by
operation of law, has commenced the exercise of one or more of the remedies
referred to in the applicable lease intended to dispossess us of the applicable
leased assets and is using good faith efforts to exercise such remedies (and not
merely asserting a right or claim to do so). However, if such indenture trustee
is then stayed or otherwise prevented by operation of law from exercising such
remedies, such indenture trustee will not divest the owner lessor of its
interest in such collateral until the earlier of (1) the expiration of the 180
day period following the commencement of such stay or other prevention or (2)
the date of repossession of the applicable leased assets under the related
lease.
Notwithstanding the foregoing to the contrary, during the continuance of an
Indenture Event of Default which constitutes a Lease Event of Default, the
applicable indenture trustees shall (to the exclusion of us and the owner
lessors) direct all votes with respect to the leased assets under the applicable
ownership and operating agreements.
Upon the occurrence of any Lease Event of Default with respect to the
payment of the equity portion only of rent, the applicable indenture trustee
will not be entitled to exercise remedies under the applicable indenture for a
period of 180 days unless the applicable owner lessor or owner investor consents
to the declaration of a Lease Event of Default under the related lease by such
indenture trustee.
Upon (a) the occurrence of an Indenture Event of Default arising out of a
Lease Event of Default caused by a Change of Control and (b) acceleration of the
lessor notes, a Change of Control premium of 1% will be payable.
In the event of the bankruptcy of an owner investor or an owner lessor, the
ability of the indenture trustee to exercise its remedies under the applicable
lease indenture against the bankrupt party might be limited and payments
required to be made under the applicable lease might be interrupted, although
the indenture trustee would retain its status as a secured creditor in respect
of the applicable owner lessor's interest in the applicable lease and leased
assets. In addition, in the event of a bankruptcy of an owner lessor, it is
possible that its lease might be rejected as an executory contract or unexpired
lease. If the lease were rejected, it would leave the indenture trustee as a
secured creditor in respect of such owner lessor's interest in such lease and
leased assets with a claim against the bankrupt estate of the owner lessor in
the amount owing under the applicable lessor notes.
If at any time after the outstanding principal amounts of lessor notes have
become due and payable by acceleration pursuant to the applicable lease
indenture:
(a) all amounts of principal, premium, if any, and interest which are
then due and payable in respect of all the lessor notes other than as a
result of such acceleration are paid in full, together with interest on all
such overdue principal and (to the extent permitted by applicable law)
overdue interest at the rate or rates specified in the lessor notes, and an
amount sufficient to cover all costs and expenses of collection incurred by
or on behalf of the holders of the lessor notes (including, without
limitation, counsel fees and expenses and all expenses and reasonable
compensation of the indenture trustee); and
(b) every other Indenture Event of Default is remedied;
then, a majority in interest of the holders of the lessor notes may, by written
notice or notices to the applicable owner lessor, the indenture trustee and us,
rescind and annul such acceleration and any related declaration of default under
the lease and their respective consequences. However, no such rescission and
annulment will extend to or affect any subsequent Indenture Event of Default or
impair any right consequent thereon, and no
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such rescission and annulment will require any holder of a lessor note to repay
any principal or interest actually paid as a result of such acceleration.
Owner lessor's right to purchase the lessor notes. Each owner lessor has
the right to purchase the lessor notes outstanding under the applicable
indenture, without any premium, at a price equal to the outstanding principal
amount of such lessor notes, together with accrued and unpaid interest thereon
to the date of purchase, if any, and all outstanding fees and expenses owed to
or incurred by the applicable indenture trustee, if:
(1) (x) an Indenture Event of Default, which also constitutes a Lease
Event of Default, has occurred and is continuing for a period of at least
90 days under such indenture without the acceleration of such lessor notes
or the exercise of any remedy under the related lease by such indenture
trustee intended to dispossess the applicable lessee of its interest in the
leased assets, (y) as a result of the occurrence and continuation of an
Indenture Event of Default, such indenture trustee accelerates, in its
discretion, or a majority in interest of certificate holders directs the
acceleration of, such lessor notes, and such acceleration has not been
rescinded, or (z) such indenture trustee has provided the applicable lessee
and the applicable owner investor written notice that it intends to
exercise, within not less than 30 days, remedies available under the
related lease intended to dispossess such lessee of its interest in the
leased assets under such lease as the result of the occurrence of an
Indenture Event of Default which also constitutes a Lease Event of Default;
(2) no Indenture Event of Default (other than solely as the result of
the occurrence of a Lease Event of Default) has occurred and is continuing
under such indenture; and
(3) the applicable owner lessor has notified such indenture trustee in
writing of its intention to purchase such lessor notes.
MODIFICATION OF LEASE DOCUMENTS
Each indenture trustee may, without the consent of the pass through
trustee, enter into any indenture or indentures supplemental to the applicable
indenture or execute any amendment, modification, supplement, waiver or consent
with respect to any other lease document related thereto to do any of the
following:
- evidence the succession of another person as manager of the owner lessor
or to evidence the succession of a successor as the indenture trustee
under such indenture, the removal of such indenture trustee or the
appointment of any separate or additional trustee or trustees and to
define the rights, powers, duties and obligations conferred upon any such
separate trustee or trustees or co-trustees;
- correct, confirm or amplify the description of any property at any time
subject to the lien of such indenture or to convey, transfer, assign,
mortgage or pledge any property to or with such indenture trustee;
- provide for any evidence of the creation and issuance of any additional
lessor notes in accordance with such indenture and to establish the form
or terms of such lessor notes;
- cure any ambiguity in, to correct or supplement any defective or
inconsistent provision of, or to add to or modify any other provisions
and agreements in, such indenture or any other lease document related
thereto, in any manner that will not, in the judgment of such indenture
trustee, materially adversely affect the interests of the holders of such
lessor notes;
- grant or confer upon such indenture trustee for the benefit of the
holders of such lessor notes any additional rights, remedies, powers,
authority or security which may be lawfully granted or conferred and
which are not contrary or inconsistent with such indenture;
- add to the covenants or agreements to be observed by us or the applicable
owner lessor and which are not contrary to such indenture, to add
Indenture Events of Default for the benefit of the holders of such lessor
notes or surrender any right or power of the applicable owner lessor;
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- effect the assumption of any or all of the lessor notes by us; so long as
the supplemental indenture will contain all of our covenants contained in
the related lease and the related participation agreement for the benefit
of the indenture trustee or the holders of any lessor notes issued under
the indenture, such that our obligations contained therein, if applicable
in the event that the related leases are terminated, will continue to be
in full force and effect;
- comply with requirements of the SEC, any applicable law, rules or
regulations of any exchange or quotation system on which the certificates
are listed, or any regulatory body;
- modify, eliminate or add to the provisions of such lease documents to
such extent as will be necessary to qualify or continue the qualification
of the pass through trust agreement (including any supplements thereto)
under the Trust Indenture Act, or similar federal stature enacted after
the closing date, and to add to the indenture such other provisions as
may be expressly permitted by the Trust Indenture Act; or
- effect any indenture or indenture supplement or any other amendment,
modification, supplement, waiver or consent with respect to such
indenture or any other lease document related thereto provided that such
supplemental indenture, amendment, modification, supplement, waiver or
consent will not, in the judgment of such indenture trustee, materially
adversely affect the interests of the holders of such lessor notes.
Notwithstanding the foregoing, no such amendment, modification, supplement,
waiver or consent will, without the consent of the holders of a majority in
interest of such lessor notes, modify the covenants set forth in this prospectus
under the captions "Description of the certificates -- Covenants -- Limitations
on incurrence of Indebtedness," "-- Limitations on Restricted Payments,"
"-- Restriction on liens," "-- Merger, consolidation or sale of substantially
all assets," "-- Sale of assets," "-- Designation of Core Subsidiaries and
Additional Subsidiaries," "-- Limitations on our activities," "-- Limitations on
transactions with affiliates" and "-- Rent Reserve Letter of Credit" and the
caption "-- The leases -- Sublease and assignment," other than modifications
having no adverse effect on the interests of the holders of such lessor notes.
In addition, no such supplement to or amendment of such indenture or the
related lease, site lease and sublease, or waiver or modification of or consent
to the terms thereof will, without the consent of the holders representing 100%
of the outstanding principal amount of such lessor notes, do any of the
following:
(1) reduce the percentage of holders of such lessor notes required to
take or approve any action thereunder;
(2) change the amount or the time of payment of any amount owing or
payable with respect to any such lessor note or change the rate or manner
of calculation of interest payable with respect to any such lessor note;
(3) alter or modify the provisions with respect to the manner of
payment or the order of priorities in which distributions thereunder will
be made as between the holders of such lessor notes and the related owner
lessor;
(4) reduce the amount (except to any amount as will be sufficient to
pay the aggregate principal of and interest on all such lessor notes) or
extend the time of payment of rent or termination value, except as
expressly provided in the related lease, or change any of the circumstances
under which rent or termination value is payable; or
(5) consent to any assignment of the related lease if in connection
therewith the applicable lessee will be released from its obligation to pay
rent and termination value, except as expressly provided herein, or
otherwise release such lessee of its obligations in respect of the payment
of rent or termination value or change the absolute and unconditional
character of such obligations.
If the pass through trustee, as the holder of the lessor notes in trust for
the benefit of the certificate holders, receives a request for its consent to
any amendment, modification, waiver or supplement under any indenture, the
related lease or other related document, the pass through trustee will send a
notice of such
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proposed amendment, modification, waiver or supplement to each certificate
holder of record as of the date of such notice. The pass through trustee will
request from the certificate holders directions as to the following decisions:
- whether or not to direct the indenture trustee to take or refrain from
taking any action which a holder of such lessor note has the option to
direct;
- whether or not to give or execute any waivers, consents, amendments,
modifications or supplements as a holder of such lessor note; and
- how to vote any lessor note if a vote has been called for with respect
thereto.
The pass through trustee will vote or consent with respect to the lessor
notes held in the pass through trust in the same proportion as the certificates
were actually voted by the certificate holders and delivered to the pass through
trustee prior to two business days before the pass through trustee directs such
action, casts such vote or gives such consent. Notwithstanding the foregoing, if
an Event of Default under the pass through trust agreement has occurred and is
continuing, the pass through trustee, subject to the voting instructions
referred to under the caption "Description of the certificates -- Events of
Default and rights upon Events of Default," may in its own discretion consent to
such amendment, modification, waiver or supplement, and may so notify the
indenture trustee.
THE LEASES
We have entered into two leases that relate to Colstrip units 1 and 2 and
two leases that relate to Colstrip unit 3.
Term and rent. The term of each lease commenced on July 20, 2000 and will
continue for a period of 36 years, which we refer to as the lease term. We have
the right to renew each lease for one or more renewal lease terms.
During the lease term and during any renewal lease terms, rent will be paid
on each January 2 and July 2, which we refer to as rent payment dates.
Use and maintenance. We will covenant to exercise all rights, powers,
elections and options available to us under the Colstrip units 1 and 2 ownership
and operating agreements, the Colstrip units 3 and 4 ownership and operating
agreement and the common facilities agreement:
(1) to cause the leased assets to be maintained in good condition,
repair and working order, in all material respects (a) in accordance with
Prudent Industry Practice, (b) in compliance with all applicable material
laws, rules and regulations of any governmental body having jurisdiction,
including, without limitation, all material environmental protection,
pollution and safety laws, and (c) in accordance with the terms of all
insurance policies required to be maintained under the applicable lease,
and
(2) to cause to be made all necessary repairs, renewals, replacements,
betterments and improvements thereof all as in our judgment may be
necessary in each case, so that the leased assets may be operated in
accordance with the Colstrip units 1 and 2 ownership and operating
agreements, the Colstrip units 3 and 4 ownership and operating agreement
and the common facilities agreement.
In the ordinary course of maintenance, service, repair or testing, we or
the operator, at no cost to the applicable owner lessor, may remove or cause to
be removed any components of the leased assets so long as we exercise all
rights, powers, elections and options available to us under the Colstrip units 1
and 2 ownership and operating agreements, the Colstrip units 3 and 4 ownership
and operating agreement and the common facilities agreement
(a) to cause such component to be replaced by replacement components,
which will be free and clear of all liens (other than permitted liens) and
in as good an operating condition as that of the component replaced
(assuming that the component replaced was maintained in accordance with the
applicable lease), and
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(b) to cause such replacement to be performed in a manner which does
not materially diminish the current value, residual value, utility or
remaining useful life of the facilities.
Notwithstanding the foregoing, if we or the operator have determined that
any parts, components or portion of the leased assets are surplus or obsolete,
such parts, components or portion may be removed without being replaced as long
as such removal would not materially diminish the current value, residual value,
utility or remaining useful life of the leased assets.
"Prudent Industry Practice" means, at a particular time, either (1) any of
the practices, methods and acts engaged in or approved by a significant portion
of the competitive electric generating industry operating in the western United
States at such time, or (2) with respect to any matter to which clause (1) does
not apply, any of the practices, methods and acts which, in the exercise of
reasonable judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a reasonable
cost consistent with good business practices, reliability, safety and
expedition. "Prudent Industry Practice" is not intended to be limited to the
optimum practice, method or act to the exclusion of all others, but rather to be
a spectrum of possible practices, methods or acts having due regard for, among
other things, manufacturers' warranties and the requirements of governmental
bodies of competent jurisdiction. Notwithstanding the foregoing, practices,
methods and acts consistent with the objectives set forth in the Reliability
Based Production program for the Colstrip facility, including without
limitation, the organizational structure and strategies being implemented at the
Colstrip facility as of the closing date, will be deemed to be "Prudent Industry
Practice."
Modifications to the leased assets. We will, subject to the Colstrip units
1 and 2 ownership and operating agreements, the Colstrip units 3 and 4 ownership
and operating agreement and the common facilities agreement, have the right,
without the consent of the pass through trustee, the applicable indenture
trustee, owner lessor or owner investor, to make or cause to be made, without
expense to such owner lessor, modifications, alterations, additions and
improvements, which we refer to as Modifications, to the leased assets as we
consider desirable in the proper conduct of our business. We will exercise all
of our rights, powers, elections and options under the Colstrip units 1 and 2
ownership and operating agreements, the Colstrip units 3 and 4 ownership and
operating agreement and the common facilities agreement to cause Modifications
to be made as may be required by any applicable law, rule or regulation, by any
agency or authority having jurisdiction, which we refer to as Required
Modifications. Except for Required Modifications, we will exercise all of our
rights, powers, elections and options under the Colstrip units 1 and 2 ownership
and operating agreements, the Colstrip units 3 and 4 ownership and operating
agreement and the common facilities agreement to prevent any Modification from
being made that would decrease the current value, residual value, utility or
remaining useful life of the leased assets or cause the leased assets to become
"limited-use" property.
Modifications that can be removed without causing material damage to the
leased assets, except for Modifications that are also Required Modifications and
Modifications financed through the leases, will remain our property. All
Required Modifications, Modifications that cannot be removed without causing
material damage to the leased assets and Modifications financed through the
leases, will automatically, upon being affixed to the leased assets, become the
property of the applicable owner lessor and be subject to the applicable lease
and the lien of the applicable lease indenture.
If we elect to finance Modifications to the leased assets through a lease,
the applicable owner investor will be given the opportunity to finance and will
consider in its sole discretion financing such Modifications in whole or in part
with additional equity. We are not obligated to accept, nor will an owner
investor be obligated to provide, any such additional equity financing.
Notwithstanding the foregoing, however, at our request, each owner lessor will
be obligated to finance Modifications through the issuance of additional
non-recourse loans under its indenture, subject to the conditions described
under the caption "Description of the certificates -- Covenants -- Limitation on
incurrence of Indebtedness" and the following conditions:
(1) except with respect to Required Modifications, there will not be
more than one such financing in any calendar year;
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(2) the additional debt will have a final maturity date no later than
the date that is two years prior to the last day of the lease term and will
be fully repaid out of additional rent, as adjusted pursuant to the lease;
(3) appropriate adjustments to rent and termination value (determined
without regard to any tax benefits associated with such modifications,
unless the applicable owner investor is financing the equity) will be made
to protect such owner investor's expected return;
(4) no Significant Lease Default or Lease Event of Default under the
applicable lease has occurred and is continuing unless the Modifications to
be constructed with such financing will cure such default and such
Modifications will be made in compliance with the applicable lease
documents;
(5) such financing is for an amount, in the aggregate, not less than
$20 million, nor greater than 100% of the costs of the Modifications being
financed, so long as (a) the aggregate balance of all lessor notes never
exceeds 87% of the fair market value of the leased assets taking into
account such Modifications and (b) the total amount of lessor notes issued
to finance Modifications does not exceed 25% of the fair market value of
the leased assets after taking into account such Modifications at the time
such lessor notes are issued and (c) the projected outstanding amount of
such lessor notes will not exceed 25% of the projected fair market value at
any time during the remainder of the applicable lease term and any renewal
lease terms (such fair market value and projected fair market value to be
determined by an appraiser selected by the owner investor and reasonably
acceptable to us);
(6) the owner investor will have received either a favorable opinion
of its tax counsel satisfactory to such owner investor to the effect that
such financing creates no unindemnified tax risk to such owner investor, or
a satisfactory indemnity against such risks;
(7) the owner investor will suffer no adverse accounting effects under
GAAP; and
(8) we will have made or delivered such representations, warranties,
covenants, opinions or certificates as the owner investor may reasonably
request.
Notwithstanding the prior provisions dealing with the financing of
Modifications through the leases, we will, subject to the conditions described
under "Description of the certificates -- Covenants -- Limitation on incurrence
of Indebtedness," at all times have the right to fund Modifications to the
leased assets other than through the leases.
Sublease and assignment. We may sublease our interest in the leased assets
under any lease without the consent of the applicable owner lessor, owner
investor, or indenture trustee, or the pass through trustee under the following
conditions:
(1) the sublessee (a) is a solvent corporation, partnership, business
trust, limited liability company, or other person or entity not subject to
bankruptcy proceedings, (b) is not involved in material litigation with the
applicable owner investor, and (c) is, or its operating and maintenance
obligations under the sublease are, guaranteed by, or such obligations are
contracted to be performed by, an experienced, reputable operator of
coal-fired electric generating assets;
(2) the applicable owner lessor, owner investor, indenture trustee and
the pass through trustee have received an opinion of counsel, which opinion
of counsel will be reasonably acceptable to the recipients, to the effect
that all regulatory approvals required to enter into such sublease have
been obtained;
(3) the sublease does not extend beyond the scheduled expiration of
the applicable lease term and any renewal lease term then in effect or
elected by us (and may be terminated upon early termination of such lease)
and is expressly subject and subordinate to the applicable lease;
(4) all terms and conditions of the applicable lease and the related
lease documents remain in effect and we remain fully and primarily liable
for our obligations under such lease and such lease documents;
(5) no Significant Lease Default or Lease Event of Default has
occurred and is continuing under the applicable lease;
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(6) the sublease prohibits further assignment or subletting;
(7) the sublease requires the sublessee to operate and maintain the
leased assets in a manner consistent with the applicable lease;
(8) the sublessee does not cause the property to become "tax-exempt
use property" within the meaning of Section 168(h) of the Internal Revenue
Code (unless we make a payment to the applicable owner investor
contemporaneously with the execution of the sublease that in the reasonable
judgment of such owner investor compensates such owner investor for the
adverse tax consequences resulting from the classification of the property
as "tax-exempt use property");
(9) the terms of the sublease do not result in any prepayment of rent
or any lump sum or advance payments received by us or any of our affiliates
in excess of $1 million in the aggregate; and
(10) we pay all reasonable documented out-of-pocket expenses of the
applicable owner lessor, owner investor and indenture trustee, and the pass
through trustee in connection with such sublease.
As a condition precedent to such sublease, we will provide the applicable
owner lessor, owner investor and indenture trustee with all documentation in
respect of such sublease and any opinion of counsel to the effect that such
sublease complies with the foregoing conditions (such documentation, counsel and
opinion to be reasonably satisfactory to such recipients).
We may assign all, but not part, of our interest in all of the leases and
the related lease documents, without the consent of the indenture trustees or
the pass through trustees if:
(1) no Significant Lease Default or Lease Event of Default has
occurred and is continuing;
(2) the certificates are rated investment grade by Moody's and S&P;
(3) Moody's and S&P confirm that such assignment and assumption will
not result in a downgrade of the then current rating of the certificates;
and
(4) we satisfy the conditions set forth in clauses (1) through (7) of
the second succeeding paragraph.
Upon the transferee's assumption of our obligations under the leases and
the other lease documents, we will, except as provided in the second succeeding
paragraph, have no further liability or obligation thereunder.
Assignment of any lease and the related lease documents will also be
subject to satisfaction of the following conditions:
(1) the applicable owner lessor and owner investor and so long as the
related lessor notes are outstanding, the applicable indenture trustee and
the pass through trustee have received an opinion of counsel, which opinion
and counsel are reasonably satisfactory to each such recipient, to the
effect that all regulatory approvals required in connection with such
transfer or necessary to assume our obligations under the applicable lease
and the related lease documents have been obtained;
(2) such transfer will be pursuant to an assignment and assumption
agreement in form and substance reasonably satisfactory to such owner
investor and so long as the related lessor notes are outstanding, the
applicable indenture trustee and the pass through trustee;
(3) the applicable owner lessor, owner investor and, so long as the
related lessor note remains outstanding, the applicable indenture trustee
and the pass through trustee have received an opinion of counsel, which
opinion and counsel are reasonably satisfactory to such parties, as to such
assignment and assumption agreement;
(4) the transfer will not cause the applicable owner investor or owner
lessor to be regulated as a public utility or public utility holding
company;
(5) the transfer will not result in a Regulatory Event of Loss;
(6) the transferee is not involved in material litigation with the
applicable owner investor; and
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(7) we will pay or cause to be paid all reasonable documented
out-of-pocket expenses of the applicable owner lessor, owner investor,
indenture trustee, and the pass through trustee in connection with such
assignment.
Notwithstanding the foregoing, we will remain secondarily liable under the
leases and the other lease documents unless either (1)(a) the senior unsecured
debt of the transferee is rated BBB+ or higher by S&P and Baa1 or higher by
Moody's at the time of such assignment and (b) such transferee or a party which
guarantees such transferee's obligations under the lease documents assigned to
such transferee (x) will have a tangible net worth of at least $1 billion after
giving effect to such transfer, and (y) will have significant experience owning
or operating coal-fired electric generating facilities in the United States, or
(2) the owner investor will have consented to such transfer.
Liens. We will not, directly or indirectly, create, incur, assume or
suffer to exist any liens or other encumbrances on the leased assets or its
interest in any lease document relating thereto, except for Permitted Liens.
The owner investors will severally agree not to create, incur, assume or
suffer to exist any lien or encumbrance on the related Collateral arising as a
result of (1) claims against or any act or omission of such owner investor that
is not related to, or is in violation of, any applicable lease document or the
transactions contemplated thereby, or that is in breach of any covenant or
agreement of such owner investor set forth therein, (2) taxes against such owner
investor for which it is not indemnified by us pursuant to the lease documents,
or (3) claims against or affecting such owner investor arising out of the
voluntary or involuntary transfer by such owner investor (other than transfers
required by the lease documents and transfers during the continuance of a Lease
Event of Default) of its interest in the applicable owner lessor, which will be
collectively referred to as "owner investor liens."
The owner lessors will severally agree not to create, incur, assume or
suffer to exist any lien or encumbrance on the Collateral arising as a result of
(1) claims against or any act or omission of such owner lessor, the owner
lessor's manager, or any affiliate thereof that is not related to, or is in
violation of, any applicable lease document or the transactions contemplated
thereby, or that is in breach of any covenant or agreement of such owner lessor,
the owner lessor's manager, set forth therein, (2) taxes imposed upon such owner
lessor, the owner lessor's manager, or any affiliate thereof for which it is not
indemnified by us pursuant to the applicable lease documents, or (3) claims
against or affecting such owner lessor, the owner lessor's manager, or any
affiliate thereof arising out of the voluntary or involuntary transfer by such
owner lessor, in its capacity as manager or its individual capacity, (other than
transfers required by the lease documents or during the continuance of a Lease
Event of Default) of any portion of its interest in the leased assets, which
will be collectively referred to as "owner lessor liens."
"Permitted Liens" means:
(1) our interests and the interests of, the owner investors, the owner
lessors, the owner lessors' manager, the indenture trustees and the pass
through trustee under any of the applicable lease documents;
(2) the owner lessor liens and the owner investor liens;
(3) our reversionary interests in the Colstrip facility site;
(4) the Colstrip units 1 and 2 ownership and operating agreements, the
Colstrip units 3 and 4 ownership and operating agreement and the common
facilities agreement;
(5) the interest of the co-owners of Colstrip unit 3 as tenants in
common in Colstrip unit 3 and the common facilities and the rights of such
owners under the Colstrip units 3 and 4 ownership and operating agreement
and the common facilities agreement;
(6) the interest of the co-owners of Colstrip unit 4 as tenants in
common of Colstrip unit 4 and the common facilities and the rights of such
co-owners under the Colstrip units 3 and 4 ownership and operating
agreement and the common facilities agreement; and
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(7) the liens and encumbrances identified on the policy of title
insurance issued in connection with the lease transaction.
Insurance. We will, at our cost and expense, maintain or cause to be
maintained (1) all risk property insurance customarily carried by prudent
operators of coal-fired electric generating facilities of comparable size and
risk to the Colstrip facility and, in any case, in an amount equal to the
maximum probable loss of the Colstrip facility and (2) commercial general
liability insurance, commercial automobile liability insurance and contractual
liability coverage, insuring against claims for bodily injury and property
damage to third parties arising out of the ownership, operation, maintenance,
condition and use of the Colstrip facility and the Colstrip site. Any such
liability insurance policy maintained by or on behalf of us will name the owner
lessor, the owner lessor's manager, the owner investor and the indenture trustee
as additional insureds. All insurance proceeds up to $25 million on account of
any damage to or destruction of the Colstrip facility will be paid to or
retained by us for application in repair or replacement of the affected property
unless a Significant Lease Default or Lease Event of Default has occurred and is
continuing. All insurance proceeds in excess of $25 million on account of any
such damage to the Colstrip facility will, if the lien of the indentures will
not have been terminated or discharged, be paid to the applicable indenture
trustee for application in accordance with the terms of leases. If any insurance
required to be maintained by us ceases to be available on a commercially
reasonable basis at the time of renewal, us and each affected owner lessor will
enter into good faith negotiations in order to obtain an alternative to such
insurance.
Termination for burdensome events. We have the option, by giving notice to
the applicable owner lessor and owner investor no later than 12 months after the
date we receive notice or actual knowledge of an event described below, to
purchase an owner lessor's interest in the leased assets and terminate the
applicable lease if: (1) a change in law causes it to become illegal for us to
continue such lease or for us to make payments under such lease or other lease
documents relating thereto, and the transactions cannot be restructured to
comply with such change in law in a manner reasonably acceptable to the parties
thereto; or (2) one or more events outside of our control has occurred which
will, or can reasonably be expected to, give rise to an obligation by us to pay
or indemnify in respect of general indemnity or tax indemnity payments under the
applicable lease documents; provided, however, that the indemnity obligation
(and the underlying cost or tax) can be avoided in whole or in part by such
purchase and the amount of such avoided payments would exceed (on a present
value basis, discounted at the discount rate, compounded on an annual basis to
the date of the termination) 3% of the purchase price of the owner lessor's
interest in the leased assets (it being understood that the related owner
investor may waive its right to "excess" payments or arrange for its own account
the payment thereof).
If, in connection with the termination of such lease with respect to one or
more Colstrip units under the circumstances described above, we purchase the
owner lessor's interest in the leased assets, execute an assumption agreement
and satisfy certain other conditions contained in the applicable indenture, we
may, so long as no Significant Lease Default or Lease Event of Default has
occurred and is continuing after giving affect to such assumption, assume the
applicable lessor notes. No termination of a lease under the circumstances
described above will be effective (regardless of whether the owner lessor elects
to sell or retain its interest in the leased assets in connection therewith)
unless and until either we assume the related lessor notes in accordance with
the provisions of the related lease indenture or the applicable owner lessor
have paid all outstanding principal and accrued interest on such lessor notes
and all other amounts due under the lease indenture on such proposed date of
termination. Pursuant to the participation agreements, we also have the option
of purchasing the beneficial interest of the applicable owner investor under
such circumstances and waive such termination right.
Termination for obsolescence. We may, so long as no Lease Event of Default
has occurred and is continuing, terminate a lease in whole or with respect to
any Colstrip unit at any time on or after the fifth anniversary of the closing
date if our board of managers determines in good faith that:
(1) such Colstrip unit(s) are economically or technologically obsolete
as a result of a change in applicable law, regulation, or tariff of general
application or imposition by the FERC or any other governmental entity
having or claiming jurisdiction over us, or such Colstrip unit(s) of any
conditions or
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requirements (including without limitation, requiring significant capital
improvements to Colstrip units upon the initial issuance, continued
effectiveness or renewal of any license or permit required for the
operation or ownership of such Colstrip unit(s); or
(2) such Colstrip unit(s) are otherwise economically or
technologically obsolete or surplus to our needs or no longer useful in our
trade or business, including without limitation, as a result of a change in
the markets for the wholesale purchase and/or sale of energy or any
material abrogation of power purchase agreements.
In order to exercise such termination option, we must give the applicable
owner lessor, owner investor and indenture trustee and pass through trustee six
months' prior notice, containing a certification by our board of managers.
Notwithstanding the foregoing, so long as the related lessor notes are
outstanding, we will not terminate a lease with respect to any Colstrip unit
pursuant to the foregoing, unless all of the leases for which we are the lessee
related to such obsolete, surplus or unusable Colstrip unit are also terminated.
In the event of such an early termination, we will, as non-exclusive agent
for the applicable owner lessors, use commercially reasonable efforts to obtain
bids and sell the applicable owner lessor's interest in such obsolete, surplus
or unusable Colstrip units on the termination date, all of the proceeds of which
will be for the account of such owner lessors. The purchaser of such interest in
the leased assets will not be us, any of our affiliates or any third party with
whom we, or any of our affiliates has an arrangement to use or operate the
affected Colstrip units to generate power for our benefit, or the benefit of our
affiliate after termination of the applicable lease.
No termination of a lease under the circumstances described above will be
effective (regardless of whether any owner lessor elects to sell or retain its
interest in the leased assets in connection therewith) unless and until the
applicable owner lessors pay all outstanding and accrued interest of the lessor
notes relating to the affected unit and all other amounts due under the lease
indenture on such proposed date of termination.
Unless the applicable owner lessor elects to retain its interest in the
leased assets, we may, not more than 30 days prior to the proposed termination
date, revoke our notice of termination. In such event, the applicable lease will
continue in effect.
On the termination date, we will pay such owner lessor the amount, if any,
by which the applicable termination value exceeds the proceeds received by such
owner lessor from such sale, plus the make whole premium, if any, arising from a
redemption of the lessor notes in connection therewith pursuant to clause (2)
above (provided, however, that if the proceeds of the sale received by the owner
lessor exceed the applicable termination value, such owner lessor will pay a
portion of such premium up to but not exceeding such excess).
Event of loss. An "Event of Loss" with respect to any Colstrip unit or
units, as the case may be, or in the case of a Regulatory Event of Loss, all
units in which the applicable owner lessor has an interest, will be deemed to
have occurred with respect to such Colstrip unit or Colstrip units and the
corresponding interests in the Colstrip common facilities allocated to such
Colstrip unit or Colstrip units upon the occurrence of any of the following
events:
(1) loss of any Colstrip unit or use thereof due to destruction or
damage to such Colstrip unit or the Colstrip common facilities that is
beyond economic repair or that renders such Colstrip unit permanently unfit
for normal use;
(2) damage to any Colstrip unit or the Colstrip common facilities that
results in an insurance settlement with respect to such Colstrip unit on
the basis of a total loss, or an agreed constructive or a compromised total
loss;
(3) seizure, condemnation, confiscation or taking of, or requisition
of title to or use of, any Colstrip unit by any governmental authority (a
"Requisition") following exhaustion of all permitted appeals or an election
by us not to pursue such appeals (provided that no such contest will extend
beyond the earlier of (x) the date which is one year after the loss of such
title, or (y) the date which is 36 months prior to the end of the lease
term and any renewal lease term then in effect or elected by us), but, in
any case
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involving Requisition of use but not of title, only if such Requisition of
use continues beyond the lease term or any renewal lease term then in
effect or elected by us; and
(4) a Regulatory Event of Loss.
If an Event of Loss with respect to one or more Colstrip units described in
clauses (1) or (2) above occurs, we may elect to either (a) if no Significant
Lease Default or Lease Event of Default has occurred and is continuing, and
subject to certain other specified conditions, rebuild or replace the affected
Colstrip units so that such Colstrip units will have a current and residual
value, remaining useful life, and utility at least equal to its condition prior
to the rebuilding, assuming such Colstrip units were in the condition and repair
prescribed by the applicable lease or (b) terminate the leases with respect to
the affected Colstrip units and pay the applicable termination value.
If we elect not to rebuild or replace the affected Colstrip units following
the occurrence of an Event of Loss described in clauses (1) or (2) above, or
upon the occurrence of any other Event of Loss, we will terminate the leases
with respect to such Colstrip units and pay the applicable owner lessor (a) the
applicable termination value plus (b) certain other amounts, that, in the
aggregate, will be an amount at least sufficient to pay the outstanding
principal of and accrued interest on the related lessor notes, whereupon such
leases will terminate with respect to such Colstrip units.
Notwithstanding the foregoing, in the case of a Regulatory Event of Loss so
long as no Significant Lease Default or Lease Event of Default has occurred and
is continuing and certain other conditions are satisfied, we may assume the
applicable lessor notes in accordance with the provisions of the lease
indenture. If we assume the lessor notes our obligation to pay applicable
termination value will be reduced by the outstanding principal amount and
accrued interest of the lessor notes we assumed.
Our right to rebuild or replace the affected Colstrip units will be subject
to the satisfaction of our obligation to, among other things:
(1) deliver to the owner lessors a report of an independent engineer
to the effect that the rebuilding or replacing of the affected Colstrip
units are technologically feasible and economically viable and that such
rebuilding or replacing can be completed at least 36 months before the end
of the lease term and any renewal lease term then in effect or elected by
us;
(2) deliver to the owner lessors an appraisal of an independent
engineer to the effect that the affected Colstrip units will have at least
the same value, residual value, utility and useful life as such Colstrip
units immediately prior to the Event of Loss;
(3) deliver to the owner lessors either (a) a tax opinion of our
counsel stating that, assuming the proposed rebuilding or replacement is
completed in a manner and within the time proposed, such rebuilding or
replacement will not cause any unindemnified adverse tax consequences, or
(b) an indemnity against such adverse tax risk from an entity that meets
certain minimum credit standards;
(4) demonstrate that we possess adequate financial resources, from
insurance proceeds or otherwise, to complete the rebuilding or restoration
of the Colstrip units;
(5) deliver to the owner lessors a certificate from us to the effect
that we reasonably believe that we will have sufficient funds available to
continue to pay rent during the rebuilding or replacing period; and
(6) commence the rebuilding or replacing as soon as practicable after
we notify the applicable owner lessor and indenture trustee of our intent
and, in any event, within 18 months of the occurrence of the event that
caused the Event of Loss.
CONSEQUENCES OF LEASE EVENTS OF DEFAULT
Upon the occurrence and continuance of any Lease Event of Default, the
applicable owner lessor may declare the lease to be in default. Except as
provided below, such owner lessor may at any time thereafter, so
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long as we have not cured all outstanding Lease Events of Default, exercise one
or more of the remedies set forth in such lease, including:
- seeking specific performance of our obligations under such lease and the
other applicable lease documents by appropriate court actions, either at
law or equity, or recover damages for breach thereof;
- terminating such lease, whereupon we will be required to return
possession of the owner lessor's interest in the leased assets to such
owner lessor, and our right to the possession and use of such interest
under the lease will absolutely cease and terminate, but we will remain
liable as provided in such lease;
- selling the applicable interest in the leased assets and Colstrip
facility site at public or private sale, free and clear of our rights;
- holding, keeping idle or leasing to others the applicable interest in the
leased assets and Colstrip facility site, free and clear of our rights
under such lease; or
- exercising its rights under the applicable Rent Reserve Letter of Credit
and applying the proceeds thereof against the debt portion of any amounts
owed under the lessor notes by the lessee under any of the lease
documents.
Upon the occurrence and continuance of any Lease Event of Default and so
long as the applicable owner lessor will not have sold its interest in the
leased assets and Colstrip facility site, such owner lessor may terminate the
applicable lease and require us to pay any accrued and unpaid rent due before
such termination date, any other amounts due and payable under the lease
documents, plus an amount equal to the excess, if any, of the applicable
termination value over the fair market sales value of its interest in the leased
assets and Colstrip facility site, as of such termination date. If the owner
lessor elects to sell its interest in the leased assets, it may require us to
any accrued and unpaid rent due before such sale, any other amounts due and
payable under the applicable lease documents, plus an amount equal to the
excess, if any, of the applicable termination value over the fair market sales
value of its interest in the leased assets and Colstrip facility site. The
amounts payable under the immediately proceeding sentence will be sufficient to
pay the principal, premium, if any, and interest due on the related lessor
notes.
Owner lessor's right to perform. Subject to the provisions of the last
sentence of this paragraph, if we fail to make any payment required to be made
under a lease or perform or comply with any other obligations under a lease and
such failure continues for 10 days after notice thereof, the applicable owner
lessor or owner investor may make such payment or perform or comply with such
obligation. If we fail to make any payment of rent when due, and if, such
failure will not constitute the fourth consecutive such failure or the eighth
cumulative failure for which the owner lessor has cured such default by making
such payment, the applicable owner lessor may, at its option, at any time within
10 business days of receiving notice of such failure, pay to the indenture
trustee any amount equal to the principal of, premium, if any, and interest on
the applicable lessor notes then due together with any past due interest, and
such payment will be deemed to have cured any Indenture Event of Default that
would have otherwise arisen.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES
The following section summarizes material United States federal income tax
consequences relating to the ownership of the certificates and constitutes the
opinion of Orrick, Herrington & Sutcliffe LLP, our special tax counsel, with
respect to such consequences.
The section does not apply to you if you do not own your certificates as
capital assets for tax purposes. The section also does not apply to you if you
are subject to special tax rules, such as those that apply to:
- brokers and security dealers;
- traders in securities that elect to mark to market;
- banks;
- life insurance companies;
- tax-exempt organizations;
- persons who will hold the certificates as part of a hedging, straddle,
integrated or conversion transaction; or
- persons whose functional currency for tax purposes is not the U.S.
dollar.
This section is based upon the laws, regulations, rulings and decisions
currently in effect, which could change at any time (possibly with retroactive
effect). The discussion does not address foreign, state and local tax issues and
does not address alternative minimum tax issues. You should consult with your
own tax advisor concerning the tax consequences of owning a certificate.
CLASSIFICATION OF TRUST
Special tax counsel is of the opinion that the pass through trust (if
operated in accordance with the terms of the pass through trust agreement)
constitutes a fixed investment trust for United States federal income tax
purposes. Moreover, special tax counsel has concluded that if the pass through
trust were determined not to be a fixed investment trust, the pass through trust
would be classified as a partnership for United States federal income tax
purposes if at least 90% of the pass through trust's gross income for each
taxable year consists of "qualifying income" which, in special tax counsel's
opinion, will include any interest or gain that the pass through trust may
derive from ownership or disposition of the lessor notes.
To reduce the possibility that the IRS would seek to characterize the pass
through trust as a partnership for United States federal income tax purposes,
the pass through trust intends to make a protective "election out" of Subchapter
K of the Internal Revenue Code (which contains most of the taxing rules
applicable to partnerships). By purchasing a certificate, you consent to the
pass through trust's making this protective election. If the United States
Internal Revenue Service treats the pass through trust as a partnership and
gives effect to this election (which is not certain), your income tax reporting
should be substantially similar to the income tax reporting that is required
under the fixed investment trust rules discussed below. If the United States
Internal Revenue Service treats the pass through trust as a partnership but
determines the election out of subchapter K is not effective, the tax
consequences described below generally would apply (assuming that the pass
through trust were not also determined to be engaged in a U.S. trade or
business), but:
- income or loss with respect to the pass through trust's assets would be
calculated at the pass through trust level;
- you would be required to report your share of the pass through trust's
items of income and deduction on your tax return for your taxable year
within which the pass through trust's taxable year ends;
- you would be required to report income or loss with respect to the
certificates on an accrual basis even if you otherwise use the cash
method of accounting; and
- the bond premium and market discount rules discussed below would not
apply.
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U.S. BENEFICIAL OWNERS
This section describes your tax consequences if you are a "U.S. beneficial
owner." You are a U.S. beneficial owner if you are a beneficial owner of a
certificate and you are, for United States federal income tax purposes:
- a citizen or resident of the United States;
- a domestic corporation;
- a domestic partnership (except as may be provided in Treasury
Regulations);
- an estate the income of which is includible in gross income for United
States tax purposes regardless of its source; or
- a trust where a United States court is able to exercise primary
supervision over your administration and where one or more U.S. persons
have authority to control all your substantial decisions (or if you are a
trust that was in existence on or before August 20, 1997, you were
properly treated as a U.S. person for U.S. federal income tax purposes
under the law in effect prior to August 20, 1997 and you properly elected
to continue to be treated as a U.S. person for U.S. federal income tax
purposes subsequent to August 20, 1997).
If you are not a U.S. beneficial owner, this section does not apply to you,
and you should refer to the section entitled "Non-U.S. beneficial owners."
Interest. For United States federal income tax purposes, you will be
treated as if you directly own your pro rata share of the lessor notes held by
the pass through trust. Accordingly, interest on the lessor notes will be
taxable to you when it is received or accrued, depending upon your method of tax
accounting and assuming, as is expected, that the certificates are issued for
their face amount. Special tax counsel has advised that it does not believe that
the special rules relating to the accrual of original issue discount set forth
in Section 1272(a)(6) of the Internal Revenue Code will apply to the
certificates and therefore the pass through trusts will not provide you with the
information you would need to compute your accrual of original issue discount
under these special rules. However, this result is not clear and you should
consult your own tax advisor on this issue.
Sale of certificate. Upon a sale, exchange or redemption of a certificate,
you will generally recognize gain or loss equal to the difference between the
amount realized on the sale (not including any amounts attributable to accrued
and unpaid interest) and your adjusted basis in the certificate for United
States federal income tax purposes. Except to the extent attributable to accrued
but unpaid interest on the underlying lessor notes (and subject to the market
discount rules discussed below), any gain or loss you recognize on the sale of a
certificate will be capital gain or loss. Similar rules will apply if a lessor
note held by the pass through trust is sold, exchanged or redeemed.
Market discount
If the amount you pay for a certificate that is allocable to any of the
underlying lessor notes of the pass through trust is less than your pro rata
share of the outstanding principal amount of the pass through trust's lessor
notes (other, generally, than on original issuance), that difference will
constitute market discount, unless the market discount rules treat the
difference as de minimis. In general, unless you elect to include market
discount in income currently:
- any gain realized on a sale of a lessor note acquired with market
discount or upon any payment of principal on such a note (including, in
the case of a sale of a certificate, your allocable share of the gain
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that is attributable to the lessor notes held by the pass through trust)
will be ordinary income to the extent of accrued market discount; and
- deductions for interest on any debt you incur or continue to purchase or
carry the certificate may be deferred until you sell the certificate (or
until the underlying lessor notes are sold).
You may elect to include market discount in income currently, but generally
this election will apply to all debt instruments you acquire during or after the
first taxable year to which the election applies and you may not revoke this
election without the consent of the IRS. You should consult a tax advisor before
making this election.
Premium
If you buy a certificate for more than your pro rata share of the
outstanding principal amount of the pass through trust's lessor notes, that
excess will constitute bond premium. You may elect to amortize bond premium. If
you make this election:
- amortizable bond premium will generally be treated as a reduction of your
interest income from the lessor notes determined on a constant yield
basis;
- you will be required to reduce your basis in the lessor notes by the
amount of your amortized bond premium.
Your election to amortize bond premium will generally apply to all debt
instruments (other than tax-exempt obligations) you hold on or after the first
day of the first taxable year to which the election applies, and you may not
revoke this election without the consent of the IRS. You should consult a tax
advisor before making the election. If you do not make (or have not previously
made) the election, you will not be entitled to amortize any bond premium on the
lessor notes.
Exchange of Certificates
Special tax counsel believes that any exchange of your certificates for
certificates that are registered under the Securities Act of 1933 (as detailed
above under the caption "Description of the Certificates -- Registration rights;
liquidated damages") will not be a taxable event for Federal income tax purposes
(because the new certificates will not differ materially in kind from the
securities that you will be surrendering in the exchange), with the result that
special tax counsel believes that the holding period of your new certificates
will include the holding period of the certificates that you surrender in the
exchange and that the basis of your new certificates will be the same as the
basis of the certificates that you surrender in the exchange (as determined
immediately prior to the date of the exchange). If new certificates are not
issued in exchange for your certificates within 270 days after the date that the
certificates are issued (or under certain other circumstances) and liquidated
damages become payable on the certificates (again, as detailed above under the
caption "Description of the Certificates -- Registration rights; liquidated
damages"), these damages should be includible in your income as ordinary income
in accordance with your method of accounting.
Expenses
You will generally be entitled to deduct, consistent with your method of
accounting, your pro rata share of the fees and expenses paid or incurred by the
pass through trust. Although it is anticipated that these fees and expenses will
be borne by parties other than the pass through trust, it is possible that these
fees and expenses would be treated as constructively borne by the pass through
trust, in which event you would be required to include in income and would be
entitled to deduct your pro rata share of the fees and expenses. If you are an
individual, estate or trust, the deduction will be allowed only to the extent
that all of your miscellaneous deductions, including your share of these fees
and expenses, exceed 2% of your adjusted gross income. In addition, if you are
an individual, you may be subject to additional rules which limit the amount of
your otherwise allowable itemized deductions.
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NON-U.S. BENEFICIAL OWNERS
This section describes the tax consequences to a non-U.S. beneficial owner.
You are a non-U.S. beneficial owner if:
- you are the beneficial owner of a certificate;
- you have no connection with the United States other than holding a
certificate; and
- for United States federal income tax purposes, you are:
- a nonresident alien individual;
- a foreign corporation;
- a foreign partnership; or
- an estate or trust that is not subject to United State income tax on a
net income basis.
If you are not a non-U.S. beneficial owner, this section does not apply to
you and you should refer to the section entitled "U.S. beneficial owners."
Any gain you recognize on a sale of your certificate will not be subject to
any deduction or withholding for United States federal income tax purposes
(except possibly, for backup withholding as discussed below). Additionally, no
United States federal income tax deduction or withholding will be made from
interest paid on your certificates, provided that:
- you do not actually or constructively own 10% or more of the combined
voting power of all classes of the stock of any of the owner investors;
- you are not a controlled foreign corporation with respect to which any of
the owner investors is a "related person" within the meaning of Section
864(d)(4) of the Internal Revenue Code; and
- you provide the U.S. paying agent with a statement signed by you under
penalties of perjury that (i) certifies that you are not a U.S.
beneficial owner and (ii) provides your name and address (or, instead,
you may provide your statement to a non-U.S. securities clearing
organization or other financial institution that holds customers'
securities in the ordinary course of its trade or business and that holds
your certificates, but this entity must certify to the U.S. paying agent
that you have provided the required statement to it, or to a similar
financial institution between it and you, and must furnish the U.S.
paying agent with a copy of the statement).
Recently issued tax regulations, generally effective for payment made after
December 31, 2000 (subject to certain transition rules), attempt to unify the
certification requirement discusses above and to clarify reliance standards.
Additionally, in the case of certificates held by a foreign partnership, these
new regulations require that (a) the certification described above be provided
by the partners and by the foreign partnership and (b) the partnership provide
certain information, including a United States taxpayer identification number.
You are urged to consult your own tax advisers regarding the effect and
application of the new regulations.
BACKUP WITHHOLDING
U.S. beneficial owners. Generally, if you are a non-corporate U.S.
beneficial owner, payments made on your certificates will have to be reported to
the IRS. In addition, any proceeds received from a sale of your certificates
will generally have to be reported to the IRS. Backup withholding, at the rate
of 31%, may apply to payments made on your certificates and to proceeds received
from a sale of your certificates, if you fail to provide an accurate certified
taxpayer identification number to the appropriate party or if you are notified
by the United States Internal Revenue Service that you have failed to report all
interest and dividends required to be shown on your United States federal income
tax returns. Backup withholding is not an additional tax and you will be able to
claim a refund or credit for taxes withheld during any taxable year at the time
you file your U.S. federal income tax return for that year.
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Non-U.S. beneficial owners. If you are a non-U.S. beneficial owner, you
will generally be exempt from backup withholding with respect to payments made
on your certificates so long as you provide the certification described above
under "Non-U.S. beneficial owners." Even if you provide the certification,
however, payments of interest made to you will have to be reported to the United
States Internal Revenue Service by the payor on Form 1042-S.
Proceeds you receive from a sale of your certificates effected outside the
United States to or though a foreign office of a broker will generally be exempt
from backup withholding and information reporting. However, unless you certify
as to your non-U.S. status or otherwise establish an exemption, information
reporting (but not backup withholding) may apply to proceeds made though the
foreign office of a broker, if the broker is
- a U.S. person;
- a controlled foreign corporation for United States income tax purposes;
- a foreign person 50% or more of whose gross income from all sources for a
specified 3-year period is effectively connected with the conduct of a
trade or business within the United States; or
- a foreign partnership if it is engaged in a trade or business in the
United States or if 50% or more of its income or capital interests are
held by U.S. persons.
Additionally, proceeds received from a sale of your certificates effected
through the United States office of a broker will be subject to backup
withholding and reporting, unless you certify as to your non-U.S. status or
otherwise establish an exemption.
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ERISA CONSIDERATIONS
If you intend to purchase certificates with assets of an employee benefit
plan, an individual retirement account or annuity, or any fund or account
holding assets of an employee benefit plan or individual retirement account or
annuity, you should consult with your legal counsel about any potential
consequences of this investment under the fiduciary responsibility provisions of
the Employee Retirement Income Security Act of 1974, as amended, known as ERISA,
and the provisions of ERISA and the Code that prohibit fiduciaries and other
individuals who have a particular relationship to the employee benefit plan from
engaging in certain transactions with plan assets.
For purposes of this discussion, the term plan will be used to include
employee benefit plans, individual retirement accounts and annuities and any
entity holding the assets of such plans, account or annuities. ERISA and the
Code require fiduciaries to act solely in the interest of participants and
beneficiaries of plans. Generally, a fiduciary status is any person who
exercises discretionary authority or control with respect to the assets of a
plan. If you are a plan fiduciary, before you invest in a certificate, you
should determine whether this investment is permitted under the documents
governing the plan and is appropriate for the plan in view of its overall
investment policy and the composition and diversification of its portfolio,
taking into account the limited liquidity of the certificates.
In addition, ERISA and the Code prohibit a wide range of transactions
involving the assets of a plan and persons who have certain specified
relationships to the plan, known as parties in interest under ERISA or
disqualified persons under the Code. These prohibited transactions include,
among other things, the sale of property, lending of money, or furnishing of
goods or services between a plan and a party in interest and the transfer to, or
use by or for the benefit of, a party in interest of any assets of the plan.
Further, if a plan invests in the certificates, the assets of the related
pass through trust may also be considered assets of the plan. If the assets of a
pass through trust are considered plan assets, the operation of the pass through
trust might give rise to one or more nonexempt prohibited transactions. In
addition, as a plan fiduciary, you may be deemed to have improperly delegated
your investment management responsibilities to the pass through trustee with
respect to those assets of the pass through trust deemed to be plan assets.
When a plan acquires an equity interest in another entity, such as the pass
through trusts, and the equity interest is neither a publicly-offered security
nor is issued by an investment company registered under the Investment Company
Act of 1940, the plan's assets include both the equity interest and an undivided
interest in each of the underlying assets of the entity unless it is established
either that the entity is an operating company or that equity participation in
the entity is not significant. The pass through trusts would not be considered
operating companies for this purpose. In general, an equity interest is an
interest in an entity other than an instrument that is treated as indebtedness
under applicable local law and that has no substantial equity features. We
believe that the certificates will be treated as equity interests in the pass
through trusts under the applicable regulations issued by the U.S. Department of
Labor.
If you invest plan assets in the certificates, your participation would not
be considered significant if less than 25% of the value of the certificates is
held by benefit plan investors immediately after the most recent acquisition of
a certificate. Benefit plan investors include employee benefit plans governed by
ERISA, certain plans not subject to ERISA (for example, governmental plans,
foreign plans, certain individual retirement accounts and entities whose assets
are treated as plan assets) and entities deemed to be holding the assets of any
such plan. We will not restrict or monitor investment in and transfer of the
certificates with respect to this 25% limit. Therefore, it is possible that
during the term of the certificates, 25% or more of the certificates will be
held by plans and other benefit plan investors. In this situation, if you invest
plan assets in the certificates, your investment would be considered an
investment in the corresponding lessor notes and an ongoing loan to the owner
lessors. This investment could, in this case, result in a prohibited transaction
or an impermissible delegation of authority if any of the assets of a pass
through trust are considered plan assets.
Further, regardless of whether the assets of a pass through trust are
considered plan assets, the initial purchasers, the pass through trustee, PPL
Montana or any of their affiliates may be a party in interest or a
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disqualified person with respect to a plan that acquires, holds or disposes of
the certificates. In this case, a plan that acquires, holds or disposes of the
certificates could be engaging in a prohibited transaction.
The certificates may be acquired, held or disposed of pursuant to and in
accordance with one or more statutory or administrative exemptions issued by the
U.S. Department of Labor. Among the administrative exemptions, known as a
prohibited transaction class exemptions or PTCEs are the following:
- PTCE 75-1: an exemption for certain transactions involving employee
benefit plans and registered broker dealers, reporting dealers and banks;
- PTCE 84-14: an exemption for certain transactions determined by an
independent qualified professional asset manager;
- PTCE 90-1: an exemption for certain transactions involving insurance
company pooled separate accounts;
- PTCE 91-38: an exemption for certain transactions involving bank
collective investment funds;
- PTCE 95-60: an exemption for certain transactions involving insurance
company general accounts; and
- PTCE 96-23: an exemption for certain transactions determined by a
qualified in-house asset manager.
While these exemptions provide relief from certain of the prohibited
transaction rules, they do not relieve a party in interest from prohibitions
against self-dealing contained in Section 406(b) of ERISA and Section
4975(c)(1)(E)-(F) of the Code. In addition, we cannot assure that any of these
administrative exemptions will be available with respect to a particular
transaction involving the certificates. Thus, if you are a plan fiduciary
considering an investment in the certificates, you should consider whether
acquiring, holding, or disposing of a certificate might constitute or give rise
to a prohibited transaction.
Governmental plans and certain church plans, while not subject to the
fiduciary responsibility provisions or the prohibited transaction provisions of
ERISA or the Code, may still be subject to state or other federal laws that are
substantially similar to these rules. If you are a fiduciary of a governmental
or church plan, you should consult with your legal counsel before investing in a
certificate.
If you are an insurance company that wants to invest assets of your general
account in the certificates, you should consider the extent to which the
investment is subject to ERISA's requirements in light of the U.S. Supreme
Court's decision in John Hancock Mutual Life Insurance Co. v. Harris Trust and
Savings Bank. You may find helpful guidance on the application of ERISA's
fiduciary rules to insurance company general account assets for policies issued
before 1999 in the final regulations issued by the Department of Labor on
January 5, 2000 under ERISA Section 401(c).
If you are acquiring or accepting a certificate or an interest in a
certificate, you will be deemed to have represented and warranted that: (i) no
plan assets have been used to acquire the certificate or an interest in the
certificate; or (ii) acquiring and holding the certificate or interest in the
certificate does not constitute or is exempt from the prohibited transaction
restrictions of ERISA and the Code.
If you are a plan fiduciary considering investing in the certificates, you
should consult with your tax and/or legal advisors regarding your fiduciary
responsibilities in connection with this investment. In particular, you should
consider the circumstances under which the assets of a pass through trust would
be considered plan assets and whether an exemption from any potential prohibited
transaction is available.
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PLAN OF DISTRIBUTION
Each broker-dealer that receives new certificates for its own account
pursuant to this exchange offer must acknowledge that it will deliver a
prospectus in connection with any resale of new certificates. This prospectus,
as it may be amended or supplemented from time to time, may be used by a
broker-dealer in connection with resales of new certificates received in
exchange for old certificates where those old certificates were acquired as a
result of market-making activities or other trading activities. We have agreed
that, for a period of 180 days after the expiration date, we will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with any such resale. In addition, until [ ], 2001, all
dealers effecting transactions in the new certificates may be required to
deliver a prospectus.
We will not receive any proceeds from any sale of new certificates by
broker-dealers. New certificates received by broker-dealers for their own
account pursuant to this exchange offer may be sold from time to time in one or
more transactions in the over-the-counter market, in negotiated transactions,
through the writing of options on the new certificates or a combination of such
methods of resale, at market prices prevailing at the time of resale, at prices
related to such prevailing market prices or at negotiated prices. Any such
resale may be made directly to purchasers or to or through brokers or dealers
who may receive compensation in the form of commissions or concessions from any
such broker-dealer or the purchasers of any such new certificates. Any
broker-dealer that resells new certificates that were received by it for its own
account pursuant to this exchange offer and any broker or dealer that
participates in a distribution of such new certificates may be deemed to be an
"underwriter" within the meaning of the Securities Act and any profit on any
such resale of new certificates and any commission or concessions received by
any such persons may be deemed to be underwriting compensation under the
Securities Act. The letter of transmittal states that, by acknowledging that it
will deliver and by delivering a prospectus, a broker-dealer will not be deemed
to admit that it is an "underwriter" within the meaning of the Securities Act.
For a period of 180 days after the expiration date we will promptly send
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker-dealer that requests such documents in the letter of
transmittal. We have agreed to pay all expenses incident to this exchange offer
(including the expenses of one counsel for the holders of the certificates)
other than commissions or concessions of any broker-dealers and will indemnify
the holders of the certificates (including any broker-dealers) against certain
liabilities, including liabilities under the Securities Act.
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INDEPENDENT CONSULTANTS
The independent engineer's report included as Appendix A to this prospectus
has been prepared by R.W. Beck, Inc., and is included herein in reliance upon
its conclusions and R.W. Beck's experience in the review of the operation of
generating facilities and the preparation of financial projections with respect
to revenues from the operation of the generating facilities. The independent
market consultant's report included as Appendix B to this prospectus has been
prepared by PA Consulting Services Inc., formerly known as PHB Hagler Bailly,
Inc., a consulting firm experienced in energy market policy, price forecasting
and economic analysis. The independent fuel consultant's report included as
Appendix C to this prospectus has been prepared by John T. Boyd Company, and is
included herein in reliance upon its conclusions and John T. Boyd Company's
experience as a mining and geological consulting firm specializing in the coal
industry. Prospective investors should read the appended reports in their
entireties and note the assumptions and qualifications stated therein.
LEGAL MATTERS
Certain legal matters will be passed upon for us by Pillsbury Winthrop LLP,
New York, New York and Orrick, Herrington & Sutcliffe LLP, New York, New York.
IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS
We have not authorized anyone to give you any information or to make any
representations about us or the transactions we discuss in this prospectus other
than those contained in this prospectus. If you are given any information or
representations about these matters that is not discussed in this prospectus,
you must not rely on that information. This prospectus is not an offer to sell
or a solicitation of an offer to buy securities anywhere or to anyone where or
to whom we are not permitted to offer or sell securities under applicable law.
The delivery of this prospectus does not, under any circumstances, mean that our
affairs have not changed since the date of this prospectus. It also does not
mean that the information in this prospectus is correct after this date.
We include cross-references in this prospectus to captions where you can
find further related discussions. The Table of Contents provides the pages on
which these captions are located.
WHERE YOU CAN FIND MORE INFORMATION
We are filing a registration statement on Form S-4 to register with the SEC
the new certificates to be issued in exchange for the old certificates. This
prospectus is part of that registration statement. As allowed by the SEC's
rules, this prospectus does not contain all of the information you can find in
the registration statement and the exhibits to the registration statement.
Upon effectiveness of the registration statement, we will file annual and
quarterly reports and other information with the SEC. You may read and copy any
reports, documents and other information we file at the SEC's public reference
rooms in Washington, D.C., New York, New York, and Chicago, Illinois. Please
call 1-800-SEC-0330 for further information on the public reference rooms. Our
filings will also be available to the public from commercial document retrieval
services and at the web site maintained by the SEC at http://www.sec.gov.
Our obligations to file reports with the SEC will be suspended if the new
certificates are held of record by fewer than 300 holders as of the beginning of
any fiscal year, and may cease filing reports with the SEC in respect of such
fiscal year, other than the fiscal year in which this registration statement is
declared effective.
131
135
INDEX TO FINANCIAL STATEMENTS
Report of Independent Accountants........................... F-3
Consolidated Balance Sheet as of December 31, 2000 and
1999...................................................... F-4
Consolidated Statement of Income and Member's Equity for the
Year ended December 31, 2000 and from inception (December
17, 1999) to December 31, 1999............................ F-5
Consolidated Statement of Cash Flows for the Year ended
December 31, 2000 and from inception (December 17, 1999)
to December 31, 1999...................................... F-6
Notes to Financial Statements............................... F-7
F-1
136
PPL MONTANA, LLC
REPORT AND FINANCIAL STATEMENTS
DECEMBER 31, 2000 AND 1999
F-2
137
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Managers and Member of
PPL Montana, LLC
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income and member's equity and of cash flows
present fairly, in all material respects, the financial position of PPL Montana,
LLC and its subsidiaries at December 31, 2000 and 1999 and the results of their
operations and their cash flows for the year ended December 31, 2000 and the
period from inception (December 17, 1999) to December 31, 1999 in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
January 29, 2001
F-3
138
PPL MONTANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, 2000 AND 1999
2000 1999
-------- --------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents (Note 1)........................ $ 79,182 $ 2,928
Trade accounts receivable, net............................ 87,152 8,973
Joint owner accounts receivable (Note 12)................. 6,666 5,920
Due from member (Note 1 and 11)........................... -- 2,999
Inventories (Note 2)...................................... 5,045 4,487
Prepayments and other..................................... 5,210 4,676
Current portion deferred income taxes (Note 11)........... 20,307 10,753
-------- --------
203,562 40,736
Property, plant and equipment, net (Notes 1 and 3).......... 427,563 811,594
Deferred income taxes (Note 11)............................. 31,098 29,824
Other (Note 4).............................................. 33,724 30,433
-------- --------
$695,947 $912,587
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Short-term debt (Note 5).................................. $ -- $365,000
Accounts payable.......................................... 50,429 7,302
Due to affiliates......................................... 17,796 1,079
Due to member (Note 1 and 11)............................. 38,338 --
Accrued expenses.......................................... 17,091 4,414
Wholesale energy commitments (Note 13).................... 22,643 16,115
-------- --------
146,297 393,910
Revolving line of credit (Note 5)........................... -- 5,000
Employee benefit obligations (Note 1 and 9)................. 8,235 10,007
Wholesale energy commitments (Note 13)...................... 75,456 80,672
Other....................................................... 12,644 6,396
-------- --------
242,632 495,985
-------- --------
COMMITMENTS AND CONTINGENT LIABILITIES
(Notes 14, 15, 17 and 18)
MEMBER'S EQUITY............................................. 453,315 416,602
-------- --------
$695,947 $912,587
======== ========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of the financial statements.
F-4
139
PPL MONTANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME AND MEMBER'S EQUITY
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM INCEPTION
(DECEMBER 17, 1999) TO DECEMBER 31, 1999
2000 1999
-------- --------
OPERATING REVENUES:
Wholesale energy marketing................................ $426,422 $ 9,598
Other revenues............................................ 2,962 115
-------- --------
Total.................................................. 429,384 9,713
-------- --------
OPERATING EXPENSES:
Operation:
Fuel................................................... 32,210 1,407
Energy purchases for wholesale......................... 91,885 1,065
Other operations and maintenance....................... 75,562 4,129
Transmission........................................... 12,553 918
Depreciation expense...................................... 13,186 734
Allowance for doubtful trade accounts receivable.......... 18,695 --
Taxes, other than income.................................. 15,186 664
-------- --------
Total............................................. 259,277 8,917
-------- --------
Operating income.................................. 170,107 796
OTHER INCOME (DEDUCTIONS), NET.............................. 1,260 (30)
INTEREST EXPENSE............................................ 25,764 2,005
-------- --------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... 145,603 (1,239)
INCOME TAX EXPENSE (BENEFIT)................................ 57,885 (399)
-------- --------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..................... 87,718 (840)
EXTRAORDINARY ITEM (NET OF INCOME TAXES) (NOTE 6)........... 1,005 --
-------- --------
NET INCOME (LOSS)........................................... $ 86,713 $ (840)
======== ========
Beginning member's equity................................... $416,602 $ --
Member contributions........................................ -- 417,442
Distribution to member...................................... 50,000 --
Net income (loss)........................................... 86,713 (840)
-------- --------
ENDING MEMBER'S EQUITY...................................... $453,315 $416,602
======== ========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of the financial statements.
F-5
140
PPL MONTANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM INCEPTION
(DECEMBER 17, 1999) TO DECEMBER 31, 1999
2000 1999
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 86,713 $ (840)
Extraordinary item (net of income taxes).................. 1,005 --
--------- ---------
Income (loss) before extraordinary item................... 87,718 (840)
Adjustments to reconcile net income (loss) to cash
provided (used) by operating activities:
Allowance for doubtful accounts...................... 18,695 --
Depreciation and amortization........................ 15,494 1,302
Wholesale energy commitment amortization............. (18,844) (734)
Changes in current assets and liabilities:
Accounts receivable.................................. (97,620) (12,893)
Due from member...................................... 41,990 (2,999)
Due from affiliate................................... 16,717 --
Inventories.......................................... (558) 167
Other assets......................................... (7,881) 1,709
Accounts payable and accrued expenses................ 55,804 10,246
Deferred income taxes................................ (10,828) 2,564
Other liabilities.................................... (454) (509)
--------- ---------
Net cash provided (used) by operating
activities...................................... 100,233 (1,987)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of assets........................................ -- (759,917)
Sale of assets............................................ 410,000 --
Property, plant and equipment additions................... (13,979) (83)
--------- ---------
Net cash provided (used) by investing
activities...................................... 396,021 (760,000)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on short-term debt............................. -- 365,000
Repayments on short-term debt............................. (365,000) --
Borrowings on revolving line of credit.................... 23,000 15,000
Repayments on revolving line of credit.................... (28,000) (10,000)
Member's contributions.................................... -- 394,915
Distributions to member................................... (50,000) --
--------- ---------
Net cash provided (used) by financing
activities...................................... (420,000) 764,915
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS................... 76,254 2,928
Cash and cash equivalents at beginning of period............ 2,928 --
--------- ---------
Cash and cash equivalents at end of period.................. $ 79,182 $ 2,928
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for interest.................. $ 16,131 $ 2,005
Cash received on income taxes, net........................ 436 --
Gain deferred on sale of assets........................... 8,221 --
Property, equipment, financing and acquisition costs
contributed by member.................................. -- 22,527
The accompanying Notes to the Consolidated Financial Statements are an integral
part of the financial statements.
F-6
141
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000 AND 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS AND CONSOLIDATION
The consolidated financial statements include the accounts of PPL Montana,
LLC, a Delaware limited liability company, and its direct and indirect
wholly-owned subsidiaries PPL Colstrip I, LLC and PPL Colstrip II, LLC
(collectively, the "Company"). The subsidiaries have no assets or operations and
bear no relationship to Colstrip Units 1 and 2. All significant intercompany
accounts and transactions have been eliminated. The Company is a wholly-owned
subsidiary of PPL Montana Holdings, LLC (the "Member"), which is an indirect
wholly-owned subsidiary of PPL Corporation.
NATURE OF OPERATIONS
The Company commenced operations December 17, 1999 after the purchase of
substantially all the generation assets and certain contracts of the utility
division of The Montana Power Company ("MPC"). The Company operates steam
generation and hydroelectric facilities throughout Montana. The Company has been
designated as an Exempt Wholesale Generator under the Federal Power Act ("FPA")
and sells wholesale power throughout the Western United States.
RECLASSIFICATIONS
Certain amounts in the 1999 financial statements have been reclassified to
conform to the current presentation.
MANAGEMENT'S ESTIMATES
These financial statements were prepared using management's estimates of
existing conditions. Actual results could differ from these estimates.
CASH EQUIVALENTS
All highly liquid debt instruments purchased with original maturities of
three months or less are considered to be cash equivalents.
CONCENTRATION OF CREDIT RISK
Financial instruments that potentially subject the Company to
concentrations of credit risk consist principally of cash and cash equivalents
and trade receivables. The Company places its cash in high credit quality
investments and limits the amount of credit exposure by any one financial
institution. Management believes that risk of loss on the Company's trade
receivables is minimized by ongoing credit evaluations of customers' financial
condition.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
The Company maintains its allowance for doubtful accounts based on
management's evaluation of the ultimate collectibility of all receivables. At
December 31, 2000, the Company recorded an allowance of approximately
$18,695,000 (See Note 14). No allowance was required at December 31, 1999.
INVENTORIES
Inventories consist mainly of fuel and materials and supplies. Inventories
are stated at the lower of cost or market. Cost is determined under the average
cost method and includes the purchase price and transportation costs of the
coal.
F-7
142
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
PROPERTY, PLANT AND EQUIPMENT
Additions to property, plant and equipment representing major renewals or
improvements are capitalized at cost. The Company records costs associated with
planned major maintenance projects in the periods in which the costs are
incurred. No costs are accrued in advance of the period in which the work is
performed. Assets are depreciated using the remaining life and straight-line
methods. Depreciation is recognized over the estimated useful life of the
related assets, ranging from 5 to 50 years for electric generation plant in
service and ranging from 5 to 40 years for non-generation property. The cost of
maintenance and repairs and replacement of minor items of property are charged
to expense as incurred. Maintenance and repair costs include costs associated
with major planned overhauls that do not improve or replace an existing asset or
extend its useful life.
EMISSION CREDITS
Emission credits are accounted for at historical cost and are charged to
operating expense as used, based on the average cost method.
ASSET IMPAIRMENT
Long-lived assets and identifiable intangibles held and used by the Company
are reviewed for impairment when events or circumstances indicate carrying
amounts may not be recoverable. Such reviews are performed in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." Impairment losses on such long-lived assets are recognized when book values
exceed expected undiscounted future cash flow with the impairment measured on a
discounted future cash flows basis.
REVENUE RECOGNITION
Revenues are recorded based on the amount of electricity delivered to
wholesale customers through the last day of each reporting period.
ACCOUNTING FOR PRICE RISK MANAGEMENT
The Company engages in price risk management activities for both energy
trading and non-trading activities as defined by EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," and
accounts for such activities in accordance with that guidance. On January 1,
2001, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). See Note 19 for additional information.
INCOME TAXES
The Company is a limited liability company and has elected to be
disregarded as a separate entity for federal and state income tax purposes. The
Company's taxable income or loss is included in the consolidated federal and
state income tax returns of PPL Corporation. The Member is a party to a tax
sharing policy that provides that the Member is responsible for taxes associated
with the Company's operations. The income tax provision for the Company is
calculated in accordance with SFAS No. 109, "Accounting for Income Taxes."
Income taxes are presented in the accompanying financial statements as if the
Company files separate returns. The current tax benefit or provision recognized
for each period is recorded in the balance sheet as amounts due from or to the
Member.
F-8
143
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
The Company has a noncontributory pension plan covering substantially all
employees. Funding is based upon actuarially determined computations that
consider the amount deductible for income tax purposes and the minimum
contribution required under the Employee Retirement Income Security Act of 1974.
The Company also provides certain health care and life insurance benefits to
retired employees.
2. INVENTORIES
Inventories consisted of the following at December 31 (thousands of
dollars):
2000 1999
------ ------
Fuel....................................................... $ 981 $1,003
Materials and supplies..................................... 4,064 3,484
------ ------
$5,045 $4,487
====== ======
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31
(thousands of dollars):
2000 1999
-------- --------
Electric generation plant (including jointly-owned
plant)............................................... $381,798 $774,868
Non-generation property................................ 27,105 12,122
Land................................................... 15,062 16,229
Construction work in progress.......................... 13,251 9,109
-------- --------
437,216 812,328
Less Accumulated depreciation.......................... 9,653 734
-------- --------
$427,563 $811,594
======== ========
4. OTHER ASSETS
Other assets consisted of the following at December 31 (thousands of
dollars):
2000 1999
------- -------
Emissions credits........................................ $19,744 $20,394
Loan fees................................................ -- 4,610
Capitalized financing costs.............................. 1,345 3,847
Prepaid rent............................................. 12,644 --
Other.................................................... 6 2,150
------- -------
33,739 31,001
Less accumulated amortization............................ 15 568
------- -------
$33,724 $30,433
======= =======
5. CREDIT ARRANGEMENTS AND FINANCING ACTIVITIES
In November 1999, the Company entered into a Bridge and Revolving Credit
Facility (the "Facility") with a syndicate of banks. The agreement provided for
three different facilities.
F-9
144
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. CREDIT ARRANGEMENTS AND FINANCING ACTIVITIES -- (CONTINUED)
At December 31, 1999, the Company had a $675,000,000 Bridge loan (the
"Bridge"), which matured in November 2000. The terms of the Bridge required
interest payments quarterly or at the end of term depending on interest rate
bases, with the outstanding principal balance due at maturity. The Bridge
required a facility fee of .175% based on the total commitment and was paid
quarterly. At December 31, 1999 the total outstanding on the Bridge loan was
$365,000,000. During 2000, the Company retired the Bridge facility.
At December 31, 1999, the Company had a $150,000,000 Tranche A Revolver
("Revolver A"), which matured in November 2002. Borrowings under Revolver A
could be utilized once the Bridge had been fully utilized. The terms of Revolver
A required interest payments quarterly with the outstanding balance due at
maturity. Revolver A required a facility fee of .20% based on the total
commitment and was paid quarterly. At December 31, 1999, there were no amounts
outstanding under Revolver A. During 2000, the Company retired Revolver A.
At December 31, 1999, the Company had a $125,000,000 Tranche B Revolver
("Revolver B"), which matures in November 2002. The maturity date may be
extended with the consent of the lenders. Revolver B provides that up to
$75,000,000 of the commitment may be used to issue letters of credit. The terms
of Revolver B required interest payments quarterly with the outstanding balance
due at maturity. Revolver B required a facility fee of .20% based on the total
commitment. Additionally, Revolver B requires a letter of credit and issuance
fee of .925% and .125%, respectively, based on the face value of the letters of
credit issued. All fees are paid quarterly. At December 31, 1999, there was
$5,000,000 outstanding under Revolver B and $2,000,000 of letters of credit
issued. During 2000, the Company reduced Revolver B to $100,000,000. At December
31, 2000, there were no amounts outstanding under Revolver B and $70,122,000 of
letters of credit issued.
The Facility provides that the interest rate, at the option of the Company,
may be based on either the LIBOR plus an Applicable Rate, or the adjusted base
rate (the "ABR") as defined in the agreement. The interest rate, as defined
above, is separately fixed for the term of each advance. The weighted average
interest rate on the Facility was 8.62% for the period from inception to
December 31, 1999 and 7.26% for the year ended December 31, 2000.
The Facility requires that the Company maintain certain financial ratios,
related to, among other things, cash flow, additional indebtedness and net worth
and restricts the sale of assets. The Company was in compliance with these
requirements as of December 31, 2000 and for the year then ended and as of
December 31, 1999 and for the period from inception to December 31, 1999.
6. EXTRAORDINARY ITEM
During 2000, the Company repaid its Bridge financing debt and reduced the
commitments under the Revolving Credit Facility. In accordance with SFAS No. 4,
"Reporting Gains and Losses from Extinguishment of Debt," an extraordinary loss
of approximately $1,005,000 (net of $653,000 of income tax benefit) was recorded
to write off deferred loan fees.
7. FINANCIAL INSTRUMENTS
The Company utilizes fixed-price forward contracts that require physical
delivery of the commodity and derivative financial instruments to manage the
risk associated with the impact of market fluctuations on its energy related
assets. The Company's derivative financial instruments consist primarily of
financial swaps.
Hedged transactions meet the requirements for hedge accounting, including
the probability of the anticipated transaction being highly correlated to price
movements of the derivative instrument. The impact of changes in the fair value
of the derivative financial instruments is deferred until the hedged
transactions are
F-10
145
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. FINANCIAL INSTRUMENTS -- (CONTINUED)
completed at which time the related deferred gain or loss is recognized in
income. In the event it becomes likely that an anticipated transaction will not
occur or that adequate correlation no longer exists, hedge accounting is
terminated and changes in the value of the derivative instrument are recognized
as income in the period of change.
At December 31, 2000, the Company held derivative financial instrument swap
contracts accounted for as hedges covering the sale of a notional amount of
4,206,000 MWh of future electrical generation. The Company had gross
unrecognized losses on these contracts of approximately $257,424,000
($154,969,000 net of taxes). The Company recorded gross losses of approximately
$20,471,000 and gross gains of approximately $32,000 for the year ended December
31, 2000 on the settlement of financial swaps. Such losses are included in
wholesale energy marketing revenue in the Consolidated Statements of Income and
Member's Equity.
The Company may enter into derivative financial contracts for speculative
purposes to take advantage of market opportunities. In accordance with EITF
98-10, the Company marks to market all speculative transactions and recognizes
any corresponding unrealized gains and losses in the Consolidated Statements of
Income and Member's Equity. At December 31, 2000, the Company held speculative
energy trading contracts for the future purchase of a notional amount of 8,424
MWh of electricity. At December 31, 2000, the Company recorded unrealized gains
on these contracts of approximately $1,717,000 as wholesale energy marketing
revenue. At December 31, 1999 and the period from inception to December 31,
1999, the Company held no speculative energy trading contracts.
The Company is exposed to credit risk in the event of non-performance by
the counter-parties to the agreements. However, the Company has established
strict counter-party credit guidelines and only enters into transactions with
counter-parties whose debt is rated investment grade or better, or to
counter-parties who have provided performance assurance such as letters of
credit or corporate guarantees. The Company considers the risk of counter-party
default to be minimal.
The carrying value of cash and cash equivalents, accounts receivable,
certain other current assets, accounts payable and debt approximate fair value
due to either the short-term nature of the instruments or variable interest
rates associated with the long-term instruments.
8. ACQUISITION
On December 17, 1999, the Company completed the acquisition of
substantially all the electric generation assets of MPC (the "Acquisition"). As
part of the Acquisition, the Company assumed from MPC certain wholesale power
purchase and sale agreements and entered into wholesale transition power sales
agreements to sell back power to MPC until no later than June 30, 2002. In
addition, the Company assumed various employee benefit obligations related to
former MPC employees retained by the Company. The transaction was treated as an
asset purchase for financial reporting purposes. Assets acquired and liabilities
assumed were recorded at their preliminary estimated fair values. Some
allocations were based on studies and valuations that were being finalized and
therefore the preliminary purchase price allocation was adjusted during 2000
(see Note 13).
F-11
146
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. ACQUISITION -- (CONTINUED)
The components of the purchase price and the preliminary allocation at
December 31, 1999 were as follows:
Consideration and acquisition costs:
Cash paid................................................... $759,917
Acquisition costs........................................... 7,184
--------
$767,101
========
Preliminary allocation of purchase price:
Property, plant and equipment............................... $805,176
Deferred income taxes....................................... 43,141
Emission credits............................................ 20,394
Inventories................................................. 4,654
Prepayments................................................. 3,538
Other assets................................................ 2,847
Due from MPC................................................ 2,000
Wholesale energy commitments................................ (97,521)
Employee benefit obligations................................ (10,450)
Other liabilities........................................... (6,678)
--------
$767,101
========
9. RETIREMENT AND OTHER BENEFITS
PENSION AND OTHER POSTRETIREMENT BENEFITS
The Company has a funded, noncontributory defined benefit pension plan
covering substantially all employees. Benefits are based upon a participant's
earnings and length of participation in the plan, subject to meeting certain
minimum requirements. The pension plan assets consist primarily of common
stocks, government and corporate bonds and temporary cash investments. The
Company also has a Supplemental Executive Retirement Plan (SERP) for certain
officers of the Company. The SERP provides certain retirement benefits to the
participants based on their compensation and years of service. Substantially all
employees will become eligible for certain health care and life insurance
benefits upon retirement.
In conjunction with the Acquisition, the Company recorded a liability for
assumed pension and postretirement medical benefit obligations. No net periodic
pension and postretirement benefit costs, actuarial gains, return on plan assets
or contributions were recorded for the period from inception to December 31,
1999.
Net pension and postretirement benefit costs were as follows for the year
ended December 31, 2000 (thousands of dollars):
POSTRETIREMENT
PENSION MEDICAL
BENEFITS BENEFITS
-------- --------------
Service cost......................................... $ 1,548 $201
Interest cost........................................ 2,111 280
Expected return on plan assets....................... (2,260) --
Prior service cost................................... 61 --
------- ----
Net periodic pension and postretirement benefit
cost............................................ $ 1,460 $481
======= ====
F-12
147
PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. RETIREMENT AND OTHER BENEFITS -- (CONTINUED)
The net periodic pension cost charged to operating expenses was $731,000.
Retiree health and benefit costs charged to operating expenses were $254,000.
Postretirement medical costs at December 31, 2000 were based on the
assumption that costs would decrease gradually from 7.25% in 2000 to 6.0% in
2006 and thereafter. A one-percent change in the assumed health care cost trend
assumptions would have the following effect (thousands of dollars):
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
Effect of service cost and interest cost
components.................................... $ 25 $ (21)
Effect on postretirement benefit obligation..... 203 (176)
The following assumptions were used in the valuation of the benefit
obligations:
POSTRETIREMENT
PENSION MEDICAL
BENEFITS BENEFITS
------------ --------------
2000 1999 2000 1999
---- ---- ----- -----
Discount rate................................... 7.5% 7.0% 7.5% 7.0%
Expected return on plan assets.................. 9.2% 8.0% -- --
Rate of compensation increase................... 4.75% 5.0% 4.75% 5.0%
The funded status of the plans at December 31, 2000 is as follows (thousands of
dollars):
POSTRETIREMENT
PENSION MEDICAL
BENEFITS BENEFITS
-------- --------------
CHANGE IN BENEFIT OBLIGATION
Benefit Obligation, January 1........................ $29,528 $ 3,500
Service cost......................................... 1,548 201
Interest cost........................................ 2,111 280
Plan amendments...................................... 1,099 --
Actuarial gain....................................... (876) 203
Net benefits paid.................................... (14) --
------- -------
Benefit Obligation, December 31...................... $33,396 $ 4,184
======= =======
CHANGE IN PLAN ASSETS
Plan assets at fair value, January 1................. $23,843 $ --
Actual return on plan assets......................... 591 --
Contributions........................................ 3,200 --
Net benefits paid.................................... (14) --
------- -------
Plan assets at fair value, December 31............... $27,620 $ --
======= =======
FUNDED STATUS
Funded status of plan................................ $(5,776) $(4,184)
Unrecognized net gain................................ 795 (106)
Unrecognized prior service cost...................... 1,036 --
------- -------
Liability recognized................................. $(3,945) $(4,290)
======= =======
Amounts for pension benefits in the preceding tables include amounts
attributable to the SERP. The projected benefit obligation, accumulated benefit
obligation and fair value of plan assets for the SERP were
F-13
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. RETIREMENT AND OTHER BENEFITS -- (CONTINUED)
approximately $1,118,000, $227,000 and $0, respectively, at December 31, 2000.
The Company did not have a material obligation to the SERP at December 31, 1999.
SAVINGS PLAN
Substantially all employees are eligible to participate in a 401(k) savings
plan. Employees may elect to save up to 16% of compensation on a pre-tax basis
subject to certain limits. The Company matches 100% of the first 4% of employee
contributions. The Company contributed approximately $1,373,000 and $18,000 to
the 401(k) plan in 2000 and 1999, respectively.
The Company has a non-funded deferred compensation plan for certain
officers of the Company. The plan provides for the deferral of up to 100% of a
participant's salary and incentive awards. The total amount deferred was
$243,000 and $0 in 2000 and 1999, respectively. Participants receive an earnings
credit on all compensation amounts deferred.
10. STOCK-BASED COMPENSATION
Certain employees of the Company participate in the Incentive Compensation
Plan ("ICP") and Incentive Compensation Plan for Key Employees ("ICPKE")
(together, the "Plans") of PPL Corporation. Under the Plans, restricted shares
of common stock as well as stock options may be granted to officers and other
key employees. Awards under the Plans are made in the common stock of PPL
Corporation by the Compensation and Corporate Governance Committee ("CCGC") of
the Board of Directors in the case of the ICP, and by the PPL Corporate
Leadership Council ("CLC") in the case of the ICPKE. Each plan limits the number
of shares available for awards to two percent of the common outstanding stock of
PPL Corporation on the first day of each calendar year. The maximum number of
options which can be awarded under each Plan to any single employee in any
calendar year is 1.5 million shares. Any portion of these shares that has not
been granted may be carried over and used in any subsequent year. If any award
lapses or is forfeited or the rights to the participant terminate, any shares of
common stock are again available for grant. Shares delivered under the Plans may
be in the form of authorized and unissued common stock, common stock held in
treasury by PPL Corporation or common stock purchased on the open market
(including private purchases) in accordance with applicable securities laws.
RESTRICTED STOCK
Restricted shares of common stock are outstanding shares with full voting
and dividend rights. However, the shares are subject to forfeiture or
accelerated payout under Plan provisions for termination, retirement, disability
and death. Restricted shares vest fully if control of PPL Corporation changes,
as defined by the Plans.
Restricted stock awards of 25,308 shares, with per share weighted-average
fair values of $24.45 were granted in 2000. Compensation expense was
approximately $100,000 for the year ended December 31, 2000. At December 31,
2000, there were 31,018 restricted shares outstanding, which include restricted
shares for employees who transferred to the Company from PPL Corporation. Of
these awards, 11,018 vest three years from the date of the grant and 20,000 vest
eleven years from the date of the grant. At December 31, 1999 no awards had been
made to the employees of the Company.
STOCK OPTIONS
Under the Plans, stock options may also be granted with an option exercise
price per share not less than the fair market value of PPL Corporation's common
stock on the date of grant. The options are exercisable beginning one year after
the date of grant, assuming the individual is still employed by PPL Corporation
or a
F-14
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. STOCK-BASED COMPENSATION -- (CONTINUED)
subsidiary, in installments as determined by the CCGC in the case of the ICP,
and the CLC in the case of the ICPKE. The CLC and CCGC have discretion to
accelerate the exercisability of the options. All options expire ten years from
the grant date. The options become exercisable if control of PPL Corporation
changes, as defined in the Plan.
At December 31, 2000, there were 100,420 stock options outstanding, with a
fair value of $3.34 per option. Fair value was determined using a modified
Black-Scholes model with the following assumptions: Risk-free interest
rate -- 6.62%; Expected stock volatility -- 21.38%; Expected dividend yield
rate -- 5.70% and Expected option life (years) -- 10.
The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" and related interpretations in accounting for
stock options. Since stock options are granted at market price, no compensation
cost has been recognized. Compensation calculated in accordance with the
disclosure requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation," was not significant for the year ended December 31, 2000 and the
period from inception to December 31, 1999.
In April 1999, PPL Corporation made its initial award of stock options
under the Plan. A summary of the stock option activity for the year ended
December 31, 2000 are as follows, which includes 30,240 options for employees
who transferred to the Company from PPL Corporation.
WEIGHTED
AVERAGE
SHARES PRICE
------- --------
Outstanding December 31, 1999............................. 30,240 $26.85
Granted................................................... 73,180 19.91
Exercised................................................. 3,000 26.85
------- ------
Outstanding December 31, 2000............................. 100,420 21.79
Exercisable December 31, 2000............................. 7,080 26.85
Outstanding options had a weighted-average remaining life of 9 years at
December 31, 2000.
11. INCOME AND OTHER TAXES
For 2000 and 1999, the corporate federal income tax rate was 35% and the
Montana corporate income tax rate was 6.75%.
F-15
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. INCOME AND OTHER TAXES -- (CONTINUED)
COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES
The tax effects of significant temporary differences comprising the
Company's net deferred income tax asset at December 31 were as follows
(thousands of dollars):
2000 1999
-------- --------
Deferred tax assets:
Accrued retirement costs................................ $ 3,122 $ 3,558
Allowance for doubtful costs............................ 7,363 --
Accrued vacation and other.............................. 2,294 1,008
Wholesale energy commitments............................ 38,639 38,611
------- -------
51,418 43,177
------- -------
Deferred tax liabilities:
Property, plant and equipment........................... 13 2,600
------- -------
Net deferred tax asset............................... $51,405 $40,577
======= =======
INCOME TAX EXPENSE
Details of the components of income tax expense (benefit), a reconciliation
of federal income taxes derived from statutory tax rates applied to income
(loss) from continuing operations for accounting purposes and details of taxes
other than income at December 31 are as follows (thousands of dollars):
2000 1999
-------- -------
Income tax expense (benefit):
Provision -- Federal.................................. $ 56,528 $(2,577)
Provision -- State.................................... 12,185 (386)
-------- -------
68,713 (2,963)
-------- -------
Deferred -- Federal................................... (9,156) 2,124
Deferred -- State..................................... (1,672) 440
-------- -------
(10,828) 2,564
-------- -------
$ 57,885 $ (399)
======== =======
RECONCILIATION OF EFFECTIVE INCOME TAX RATE:
Income tax expense (benefit) on pre-tax income at
statutory tax rate -- 35%.......................... $ 50,961 $ (434)
State income taxes.................................... 6,388 35
Other................................................. 536
-------- -------
Total income tax expense (benefit)...................... $ 57,885 $ (399)
======== =======
Effective income tax rate............................... 39.8% 32.2%
TAXES OTHER THAN INCOME:
Property taxes........................................ $ 13,200 $ 560
Generation taxes...................................... 1,665 77
Social security and other............................. 321 27
-------- -------
$ 15,186 $ 664
======== =======
F-16
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. JOINTLY OWNED FACILITIES
The Company is the operator of the jointly owned coal-fired generating
units comprising the Colstrip steam generation facility. At December 31, 2000,
the Company has a 50% leasehold interest in Colstrip Units 1 and 2 and a 30%
leasehold interest in Colstrip Unit 3 under an operating lease (see Note 15). At
December 31, 1999, the Company had a 50% ownership interest in Colstrip Units 1
and 2 and a 30% ownership interest in Colstrip Unit 3.
The Company's share of direct expenses associated with the operation and
maintenance of these facilities is included in the corresponding operating
expenses in the Consolidated Statements of Income and Member's Equity. Each
joint owner in these facilities provides its own financing. As operator of all
Colstrip Units, the Company invoices each joint-owner for their respective
portion of the direct expenses. The amount due from joint-owners was
approximately $6,666,000 and $5,920,000 at December 31, 2000 and 1999,
respectively.
At December 31, 2000, MPC continues to own a 30% interest in Colstrip Unit
4. As part of the purchase of generation assets from MPC, the Company and MPC
entered into a reciprocal sharing agreement to govern each party's
responsibilities regarding the operation of Colstrip Units 3 and 4. This
agreement provides that each party is entitled to 15% of the generation of each
of Colstrip Units 3 and 4, and is responsible for 15% of the respective
operating and construction costs, regardless of whether a particular cost is
specified to Colstrip Unit 3 or 4. However, each party is responsible for its
own fuel related costs.
13. WHOLESALE ENERGY COMMITMENTS
SUPPLY COMMITMENTS
As part of the purchase of generation assets from MPC, the Company agreed
to supply electricity to MPC under two wholesale transition service agreements
(WTSAs). One WTSA is for a term of two years from December 17, 1999 and is a
200MW firm commitment. The other WTSA covers MPC's remaining native load
commitments and is for a term from December 17, 1999 until MPC's remaining
customer load is zero, but in no event later than June 30, 2002. In accordance
with purchase accounting guidelines, the Company recorded a $52,489,000
liability as an estimate of the fair value of the contracts at the acquisition
date, including $20,156,000 recorded in 2000 upon completion of the valuation
study. The liability was recorded on a present value basis, determined using a
6.5% discount rate. Such amount is prospectively amortized as an adjustment of
wholesale energy marketing revenues over the contract terms. The Company had
sales to MPC for the year ended December 31, 2000 of approximately $113,395,000,
including amortization of approximately $22,383,000, which represented 26% of
revenue for the year. Interest expense on the amortized balance was $2,790,000
for the year ended December 31, 2000. The unamortized liability was $32,214,000
at December 31, 2000. The Company had sales to MPC from the period from
inception through December 31, 1999 of approximately $4,600,000, including
amortization of approximately $682,000 which represented 48% of revenue for the
period.
As part of the purchase of generation assets from MPC, the Company agreed
to supply electricity to the United States Government on behalf of the Flathead
Irrigation Project (FIP). Under the agreement, which expires in December 2010,
the Company is required to supply approximately 7.5MW of capacity year round,
with an additional 3.7MW during the months of April through October. In
accordance with purchase accounting guidelines, the Company recorded a
$6,616,000 liability as an estimate of the fair value of the contract at
December 17, 1999. The liability was recorded on a present value basis,
determined using a 6.5% discount rate. Such amount is prospectively amortized as
an adjustment to wholesale energy marketing revenues over the contract term. The
Company recorded amortization of $673,000 and interest expense of $424,000 on
the unamortized balance for the year ended December 31, 2000. The unamortized
liability was $6,364,000 at December 31, 2000. The Company recorded amortization
from the period from inception to December 31, 1999 of approximately $3,000.
F-17
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. WHOLESALE ENERGY COMMITMENTS -- (CONTINUED)
PURCHASE COMMITMENTS
As part of the purchase of generation assets from MPC, the Company assumed
a power purchase agreement with Basin Electric Power Cooperative, which expires
in April 2010. The agreement requires the Company to purchase up to 98MW of firm
capacity from November through April of each year. The pricing under the
agreement consists of a capacity charge that is fixed, and an energy charge
adjustment to cover certain capital and operating and maintenance costs. In
accordance with purchase accounting guidelines, the Company recorded a
$58,572,000 liability as an estimate of the fair value of the contract at
December 17, 1999. The liability was recorded on a present value basis,
determined using a 6.5% discount rate. Such amount is prospectively amortized as
an adjustment to energy purchases for wholesale over the contract term. The
Company recorded amortization of $2,830,000 and interest expense of $3,828,000
on the unamortized balance for the year ended December 31, 2000. The unamortized
liability was $59,521,000 at December 31, 2000. The Company recorded
amortization from the period from inception to December 31, 1999 of
approximately $49,000.
14. COMMITMENTS AND CONTINGENT LIABILITIES
ENVIRONMENTAL MATTERS
AIR
The Clean Air Act deals, in part, with acid rain, attainment of federal
ambient ozone standards and toxic air emissions. The Company is substantially
compliant with the Clean Air Act.
The Environmental Protection Agency ("EPA") has developed new standards for
ambient levels of fine particulates. These standards were challenged and
remanded to the EPA by the D.C. Circuit Court in 1999. The United States Supreme
Court is reviewing the Circuit Court decision. The new particulates standard, if
finalized, may require further reductions in SO(2) emissions for the Company.
Under the Clean Air Act, the EPA has been studying the health effects of
hazardous air emissions from power plants and other sources, in order to
determine what should be regulated. The EPA has determined that mercury
emissions must be regulated. The EPA is expected to develop regulations by 2004.
In 1999, the EPA initiated enforcement actions against eight utilities,
asserting that older, coal-fired power plants operated by those utilities have,
over the years, been modified in ways that subject them to more stringent "New
Source" requirements under the Clean Air Act. The EPA has since issued notices
of violation and has commenced enforcement activities against other utilities
and has threatened to continue expanding its enforcement actions. The EPA's
regional offices that regulate the Company's generation plants have indicated an
intention to issue information requests to all utilities in its jurisdiction and
have issued such a request to the Company related to the J.E. Corette Steam
Electric Station. Compliance with any such EPA enforcement action could result
in additional capital and operating expenses in amounts which are not now
determinable, but which could be significant.
The EPA is also proposing to revise its regulations in a way that will
require power plants to meet "New Source" performance standards and/or undergo
"New Source" review for many maintenance and repair activities that are
currently exempt.
REMEDIATION
In conjunction with its divestiture, the Montana Power Company prepared a
Phase I and Phase II Environmental Site Assessment. The assessment identifies
approximately $7.2 million of future capital expenditures through the year 2020
related to various groundwater remediation issues. Additional capital
expenditures could be required in amounts which are not now determinable but
which could be material.
F-18
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. COMMITMENTS AND CONTINGENT LIABILITIES -- (CONTINUED)
Future cleanup or remediation work at sites currently under review, or at
sites not currently identified, may result in material additional operating
costs for the Company that cannot be estimated at this time. The Company has
been indemnified by the Montana Power Company for any preacquisition
environmental liability. However, this indemnification is conditioned on certain
circumstances that can result in the Company and the Montana Power Company
sharing in certain costs within limits set forth in the Asset Purchase
Agreement.
In October 1999, the Montana Supreme Court held in favor of several
citizens' groups that the right to a clean and healthful environment is a
fundamental right guaranteed by the Montana Constitution. The Court's ruling
could result in significantly more stringent environmental laws and regulation
as well as an increase in citizens' suits under Montana's environmental laws.
The effect on the Company of any such changes in laws or regulations or any such
increase in citizen suits is not currently determinable but could be
significant.
GENERAL
Due to the environmental issues discussed above or other environmental
matters, the Company may be required to modify, replace or cease operating
certain plants to comply with statutes, regulations and actions by regulatory
bodies or courts. In this regard, the Company also may incur capital
expenditures, operating expenses and other costs in amounts which are not now
determinable but which could be material.
PURCHASE COMMITMENTS
The Company is party to an "all requirements" coal supply agreement with
Western Energy Company (WECO) to supply coal the Company uses to generate
electricity from interests in Colstrip Units 1 and 2. The pricing under this
agreement consists of a commodity charge and an annual fixed charge. The
commodity charge is adjusted as of March 1 and September 1 of each year based on
changes in WECO costs. The fixed charge is subject to renegotiation on July 30,
2001. Under this agreement the Company purchased approximately 1,319,000 and
36,000 tons of coal for the year ended December 31, 2000 and for the period from
inception to December 31, 1999, respectively. The agreement expires on December
31, 2009, and may be extended upon terms mutually agreeable to the parties.
The Company is party to an "all requirements" coal supply agreement and
coal transportation agreement with WECO to supply and deliver coal used to
generate electricity from interests in Colstrip Units 3 and 4. The pricing under
the coal supply agreement consists of a commodity charge and an annual fixed
charge. The pricing under the coal transportation agreement consists of an
annual fixed charge, cost reimbursement charge, operating profit fee and a
revenue credit. Under this agreement the Company purchased approximately 907,000
and 52,000 tons of coal for the year ended December 31, 2000 and for the period
from inception to December 31, 1999, respectively. The coal supply and
transportation agreements expire on December 31, 2019, and may be extended upon
terms mutually agreeable to the parties.
The Company is party to a coal supply contract to purchase coal for use at
another coal-fired plant at fixed rates. The Company purchased approximately
727,000 and 27,000 tons of coal for the year ended December 31, 2000 and for the
period from inception to December 31, 1999, respectively. The agreement expires
on December 31, 2001.
POWER EXCHANGE COMMITMENTS
The Company has a power exchange agreement which requires the Company to
deliver 118,800MWh of firm power between June 15 and September 15 of each year.
In return, the Company receives 108,000MWh of firm power between December 1 and
February 28 of each year. The agreement shall continue in effect until
terminated by either party with a three year written notice.
F-19
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. COMMITMENTS AND CONTINGENT LIABILITIES -- (CONTINUED)
SOURCE OF LABOR SUPPLY
At December 31, 2000, the Company had approximately 470 employees.
Approximately 68% and 2% of the employees are represented by the International
Brotherhood of Electrical Workers and the Teamsters, respectively. All union
contracts expire in 2001.
SALES TO CALIFORNIA INDEPENDENT SYSTEM OPERATOR
Since mid-December 2000 the U.S. Secretary of Energy ("Secretary") has
ordered a number of wholesale power sellers in the Western United States,
including the Company, to sell to the California Independent System Operator
("CAL ISO"), all amounts of energy that such sellers have available in excess of
their existing firm power commitments. The orders require that the CAL ISO first
certify on a daily basis to the Department of Energy that it has inadequate
energy supplies to meet its needs, and that it is implementing specified
conservation measures. If these certifications are made, then the CAL ISO is
authorized to request deliveries of excess energy from the sellers named in the
orders. The orders state that the CAL ISO is to allocate such requests, to the
extent feasible, in proportion to each seller's available excess power.
The Secretary has stated that he took this extraordinary action because of
an emergency that he found exists in California due to a shortage of electric
energy in the state. The Company has requested rehearing of these orders on the
grounds that they fail to provide adequate assurances that the sellers would be
paid for the power so delivered. Rehearing was granted on January 17, 2001 for
the limited purpose of receiving additional information. The most recent such
order expires on February 7, 2001.
Since mid-December through the expiration of the order, the Company has
delivered approximately 1,700 MWh to the CAL ISO. The delivered energy
represents approximately 0.2% of the Company's production for the period the
orders have been in place. The Company has not yet received payment for these
sales. The Company negotiated prices for a portion of the ordered sales with the
CAL ISO. The prices for the remaining ordered sales, which occurred in 2001,
will be established in future proceedings at the Federal Energy Regulatory
Commission ("FERC").
The Company made voluntary sales of energy to the CAL ISO prior to the date
the first order was issued. The order sales amount to approximately $18 million
and are currently scheduled to be paid in February and March 2001.
The CAL ISO's ability to pay for both the pre-order and post-order sales
will ultimately depend on the two major California electric utilities, Pacific
Gas and Electric Company and Southern California Edison Company, recovering
their financial stability, or on the State of California constructing a
financial solution to the power supply crisis currently facing the state. Both
of the utilities are experiencing severe liquidity constraints, have defaulted
on various debts and have stated publicly that they may file for bankruptcy
protection. The Company cannot predict if or when it will receive payment for
sales to the CAL ISO that have been made or may be required to make in the
future, or the final amounts of any such payments. As of December 31, 2000, the
Company has fully reserved for possible underrecoveries of payments for these
energy sales. The Company may have to add to the reserves in future periods if
it is required by the Secretary, other governmental agencies or a court to
continue to supply energy to the CAL ISO.
Litigation arising out of the California supply situation has been filed at
the FERC and in California courts against sellers of energy to the CAL ISO. The
plaintiffs and intervenors allege abuse of market power, among other things, and
seek price caps on wholesale sales in California and other Western power
markets, refunds of excess profits allegedly earned on these sales, and other
relief, including treble damages and attorneys' fees. The Company has intervened
in the FERC proceedings in order to protect the Company's interests, but have
not been named as a defendant in any of the court actions. The Company cannot
predict
F-20
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. COMMITMENTS AND CONTINGENT LIABILITIES -- (CONTINUED)
whether it will eventually be named in these lawsuits or other lawsuits and
cannot predict the outcome of any such litigation. If the eventual resolution
results in the imposition of price caps or other regulatory controls on
wholesale energy sales, our future cash flow and financial condition could be
adversely affected.
15. LEASE COMMITMENTS
In July 2000, the Company sold its investment in the Colstrip Steam
Generation Plant to owner lessors in a sale leaseback transaction whereby the
Company leased the assets from the owner lessors under a thirty-six year
operating lease. The sale proceeds were approximately $410,000,000. The Company
recorded a deferred gain on sale of approximately $8,221,000, which will be
amortized into other operations and maintenance over the term of the operating
lease on a straight-line basis. For the year ended December 31, 2000, the
Company recognized approximately $114,000 of amortization. The Company used the
sale proceeds to reduce outstanding debt and make distributions to the Member.
The Company leases a 50% interest in the Colstrip Units 1 and 2 and a 30%
interest in Unit 3, through four non-cancelable operating leases, which expire
in thirty-six years. The Company is required to pay all expenses associated with
the operations of the generation units. The leases place certain restrictions on
the Company's ability to incur additional debt, sell assets and declare
dividends and require the Company to maintain certain financial ratios related
to cash flow and net worth. Rent expense charged to operations and maintenance
expense has been recognized on a straight-line basis and for the year ended
December 31, 2000 was approximately $9,100,000.
The Company leases a portion of a building under a non-cancelable operating
lease, which expires in 2002. The Company also leases operating equipment under
various short-term leases.
The future minimum lease payments under operating leases are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
- -----------------------
2001........................................................ $ 43,273
2002........................................................ 49,277
2003........................................................ 46,973
2004........................................................ 43,511
2005........................................................ 38,084
Thereafter.................................................. 530,866
--------
$751,984
========
16. RELATED PARTY TRANSACTIONS
The Member has interests in other entities with whom the Company has
transactions. Although transactions with these entities cannot be presumed to be
at arms length, it is the intention of the parties and the Company that these
transactions be conducted at terms comparable to those available with third
parties.
The Company has executed a brokering and contract management agreement with
PPL EnergyPlus. The agreement authorizes PPL EnergyPlus to act as exclusive
agent in managing the Company's wholesale energy supply and energy and capacity
purchase contracts. The agreement also grants PPL EnergyPlus express authority
and responsibility for managing the sale of energy in excess of wholesale
contract commitments. The Company retains title to all energy that is sold into
the wholesale market. The Company must pay PPL EnergyPlus a fee to cover its
annual operating expenses related to its responsibilities under the brokering
and contract management agreement. The total amount paid to PPL EnergyPlus was
$5,041,000 for the year
F-21
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. RELATED PARTY TRANSACTIONS -- (CONTINUED)
ended December 31, 2000 and is included in other operations and maintenance on
the Consolidated Statements of Income and Member's Equity. The amounts due to
PPL EnergyPlus at December 31, 2000 and 1999 were $420,000 and $1,079,000,
respectively, and are included in due to affiliates on the Consolidated Balance
Sheets.
The Company has a memorandum of understanding ("MOU") with PPL EnergyPlus
regarding the supply of energy to satisfy PPL EnergyPlus' obligations under its
retail contracts. The MOU is effective through December 31, 2000. The Company
plans to renew the MOU with substantially the same terms. The MOU provides that
the Company will provide the energy necessary for PPL EnergyPlus to supply
energy services to its customers, taking into account the Company's energy
commitments to third parties under wholesale supply agreements. PPL EnergyPlus
will take title to the energy and has the sole authority to sell the energy and
assumes all customer credit risks.
The MOU provides for two different pricing mechanisms, dependent upon the
underlying PPL EnergyPlus retail contract structure. If PPL EnergyPlus sells
power at a fixed price during the contract term, the Company will supply energy
to PPL EnergyPlus for the term of the contact at the Mid-Columbia forward price
agreed by the Company and PPL EnergyPlus at the date the contract is executed.
If PPL EnergyPlus enters into a floating price agreement, the Company will
supply energy to PPL EnergyPlus for the term of the contract at a floating
price. The floating price PPL EnergyPlus will pay will be the Mid-Columbia
forward price plus $1.00 per MWh. If PPL EnergyPlus enters into a retail contact
to sell energy at a price that is structured with both fixed and floating
components, the pricing will use a combination of the above mechanisms. Total
energy sales to PPL EnergyPlus were $32,548,000 for the year ended December 31,
2000 and are included in wholesale energy marketing revenues on the Consolidated
Statements of Income and Member's Equity. The amount due from PPL EnergyPlus at
December 31, 2000 was $12,750,000 and is included in due to affiliates on the
Consolidated Balance Sheet. There were no sales to PPL EnergyPlus under the MOU
for the period from inception to December 31, 1999.
The Member has guaranteed certain obligations of the Company for up to $20
million under power purchase and sales agreements at December 31, 2000. There
were no guarantees at December 31, 1999.
17. REGULATORY ISSUES
The Company has eleven hydroelectric facilities and one storage reservoir
licensed by FERC pursuant to the FPA under long-term licenses which expire on
varying dates from 2009 through 2040. Pursuant to Section 8(e) of the FPA, FERC
approved the transfer from MPC of all pertinent licenses and any amendments
thereto, for the ownership and operation of these facilities purchased by the
Company.
The Kerr Dam Project license was jointly issued by FERC to MPC and the
Confederated Salish and Kottenai Tribes of the Flathead Reservation in 1985, and
required MPC to hold and operate the project for 30 years. The license required
MPC, and subsequently the Company as a result of the purchase of the Kerr Dam
from MPC, to continue to implement a plan to mitigate the impact of the Kerr Dam
on fish, wildlife and habitat. The implementation will require payments totaling
approximately $8,450,000 between 2001 to 2020. Additionally, the Company is
required to make annual payments to the Confederated Salish and Kootenai Tribes
for the use of the property the Kerr Dam occupies. The annual payments increase
in June of each year based on the CPI-Urban index. The annual payment for the
period from July 2000 through June 2001 is approximately $14,412,000. The
Company expensed approximately $14,240,000 for the year ended December 31, 2000,
and $534,000 for the period from inception through December 31, 1999.
The Company is subject to the jurisdiction of certain federal, regional,
state and local regulatory agencies with respect to air and water quality, land
use and other environmental matters. The operations of its generating facilities
are subject to the Occupational Safety and Health Act of 1970 and comparable
state
F-22
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PPL MONTANA, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
17. REGULATORY ISSUES -- (CONTINUED)
statues. In addition, the Company is subject to the jurisdiction of the Nuclear
Regulation Commission in connection with its operation of level and density
monitoring devices. Management believes at this time that it is operating in
accordance with the laws and regulations of the various agencies and there are
no current actions which will have a material effect on its business, financial
condition or results of operations.
18. PENDING TRANSACTIONS
PPL Global, Inc., an indirect wholly-owned subsidiary of PPL Corporation
and our affiliate, was party to separate Asset Purchase Agreements (each an
"APA") with Portland General Electric Company ("PGE") and Puget Sound Energy,
Inc. ("PSE") to purchase their respective interests in the Colstrip Units and
certain related transmission assets and rights. The interested parties mutually
agreed to terminate the APA's.
The MPC APA, previously assigned to the Company by PPL Global, provided if
neither the PSE or PGE acquisitions are consummated the Company is required to
purchase a portion of MPC's interest in the 500 kilovolt Colstrip Transmission
System ("CTS") for $97,000,000 for which regulatory approval has been received.
The Company is currently in discussions with MPC to pursue alternatives to
acquiring this entire interest in the CTS as contemplated by the APA. These
discussions are ongoing, therefore, the Company cannot predict whether it will
buy all or less than all of MPC's entire interest in the CTS, or what the
purchase price will be if a purchase occurs.
19. NEW ACCOUNTING STANDARDS
On January 1, 2001, the Company adopted SFAS 133, which requires that every
derivative instrument be recorded on the balance sheet as an asset or liability
measured at its fair value and that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. The Company, through the use of a cross-functional project team, has
completed the process of identifying all derivative instruments, determining
their fair market values, designating and documenting hedge relationships and
evaluating the effectiveness of those hedge relationships.
In accordance with the transition provisions of SFAS 133, the Company
expects to record a net-of-tax cumulative-effect-type charge of $154,969,000 in
accumulated other comprehensive income to recognize at fair value all
derivatives that are designated as cash flow hedging instruments. This
adjustment will be attributed to financial swaps in which the Company has
reserved and stands ready to deliver energy from the planned output of its
generating units. The Company uses these contracts to mitigate commodity price
risk.
Future changes in the fair market values of these derivative instruments,
to the extent that the hedges are effective at mitigating the underlying
commodity risk, will be recorded in other comprehensive income. At the date the
underlying transaction occurs, the amounts accumulated in other comprehensive
income will be reported in the Consolidated Statements of Income. To the extent
that the hedges are not effective, the ineffective portion of the changes in the
fair market value will be recorded directly in earnings. The Company expects to
reclassify into earnings during the next twelve months $118,920,000 from the
transition adjustment that will be recorded in accumulated other comprehensive
income. The cash flow hedges described above cover various periods of time from
January 2001 through December 2006.
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APPENDIX A: INDEPENDENT ENGINEER'S REPORT
159
[R.W. BECK LOGO]
July 13, 2000
Chase Securities Inc.
270 Park Avenue
New York, NY 10017
Ladies and Gentlemen:
SUBJECT: INDEPENDENT ENGINEER'S REPORT ON PPL MONTANA, LLC
Presented herein is the report (the "Report") of our review and analyses of
an interest in the 2,094 MW (net) coal-fired power plant located in Colstrip,
Montana (the "Colstrip Facility"); the 154 MW (net) Corette coal-fired power
plant located near Billings, Montana (the "Corette Facility"); the 577 MW
Missouri-Madison, Thompson Falls, Kerr and Mystic hydroelectric plants
(collectively, the "Hydroelectric Facilities" and, together with the Colstrip
and Corette Facilities, the "Plants"); and an interest in the Colstrip
Transmission System (the "Colstrip Transmission System" and, together with the
Plants, the "Montana Portfolio"). PPL Montana, LLC ("PPL Montana"), an indirect
wholly-owned subsidiary of PPL Corporation, acquired the Plants from Montana
Power Company ("MPC") on December 17, 1999. PPL Montana has a contingent
contract to purchase an interest in the Colstrip Transmission System currently
owned by MPC.
The acquisition of the Montana Portfolio was supported, in part, through a
credit facility (the "Credit Facility") from a syndicate of banks led by The
Chase Manhattan Bank. PPL Montana is currently entering into sale leaseback
transactions for its Colstrip Facility assets pursuant to leveraged lease
transactions (the "Leases") with four owner lessors. PPL Montana will use the
proceeds of the Leases to pay down the Credit Facility. Accordingly, a pass
through trust is issuing $338,000,000 of 8.903% Pass Through Certificates due
2020 (the "Certificates"). The Certificates represent fractional undivided
interests in a pass through trust consisting solely of secured lease obligation
notes called lessor notes. The lessor notes will be issued by the owner lessors
and be secured by collateral which includes certain ownership interests of the
owner lessors in the Colstrip Facility and certain of the owner lessors' rights
under the Leases and the other lease documents. The proceeds from the issuance
of the lessor notes, together with the proceeds of each owner participant's
equity investment in the related owner lessor, will be used by each owner lessor
to finance the purchase of its interest in the Colstrip Facility from PPL
Montana and finance certain Lease related transaction expenses. PPL Montana will
be responsible for making rent payments on the Leases (the "Rent"). The Rent is
paid at the same priority as payments on any other senior debt of PPL Montana
(together with the Rent, the "Fixed Charges").
The Colstrip Facility consists of four operating coal-fired electric
generating units, including associated common facilities. Colstrip Units 1 and 2
have a nominal net generating capability of 614 MW and are jointly owned by PPL
Montana and Puget Sound Energy, Inc. ("Puget") as tenants in common, each having
a 50 percent ownership interest. Colstrip Units 3 and 4 have a nominal net
generating capability of 1,480 MW and are jointly owned according to the
following allocation: 25 percent of both units is owned by Puget, 20 percent by
Portland Electric Generating Company ("Portland"), 15 percent by Avista
Corporation ("Avista"), and 10 percent by PacifiCorp. Thirty percent of Colstrip
Unit 3 is owned by PPL Montana and MPC has a leasehold interest in 30 percent of
Colstrip Unit 4. PPL Montana operates the Colstrip Facility.
PPL Montana and MPC have executed a Reciprocal Sharing Agreement dated
December 17, 1999 to coordinate the operation of their respective shares of
Colstrip Units 3 and 4 in order to ensure conformity to the terms of certain MPC
agreements. MPC's output from its Colstrip Unit 4 interest serves two Power
Sales Agreements (the "PSAs"). These consist of a PSA with Duke Energy Trading
and Marketing and a PSA
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with Puget, both with terms through December 29, 2010. There are certain
contractual obligations contained in the PSAs and certain Colstrip Unit 4
agreements with respect to the operation of Colstrip Units 3 and 4. Under these
various agreements, PPL Montana's and MPC's interests in Colstrip Units 3 and 4
are operated jointly as twin units. The contractual obligations relative to the
joint operation of Colstrip Units 3 and 4 include, but are not limited to: (1)
governance under the various agreements; (2) the apportionment of outputs of the
units to meet the obligations under the PSAs; and (3) the means of sharing the
cost of operation, maintenance, and capital improvements between the owners of
Colstrip Units 3 and 4.
Colstrip Units 1 and 2 receive coal under a Coal Supply Agreement between
MPC, Puget and Western Energy Company ("Western Energy") entered into July 30,
1971 and continuing through December 31, 2009. Colstrip Units 3 and 4 receive
coal under an Amended and Restated Coal Supply Agreement between MPC, Puget,
Portland, Avista, PacifiCorp and Western Energy entered into August 24, 1998,
continuing through December 31, 2019. Under the terms of the Asset Purchase
Agreement, both coal supply agreements have been assigned by MPC to PPL Montana
with no changes in terms or conditions. Both agreements may be extended on terms
mutually agreeable if coal is available that may be mined and used economically.
The Colstrip Transmission System consists of a portion of the Colstrip 500
kilovolt ("kV") Switchyard, 500 kV facilities at the Broadview Substation, and
approximately 249 miles of 500 kV transmission system extending from the
Colstrip Facility to near the town of Townsend, Montana where it physically
interconnects with the transmission system of the Bonneville Power
Administration ("BPA"). PPL Montana has a contingent contract to purchase MPC's
Colstrip Units 1, 2 and 3 ownership interest in the Colstrip Transmission
System, as shown in Table 1 in the section entitled "Colstrip Transmission
System". The Colstrip Transmission System will continue to be operated by MPC.
The Colstrip Transmission System is divided into two distinct segments: the
approximate 115-mile long Colstrip-Broadview segment and the approximate
133-mile long Broadview-Townsend segment. The ownership interests in the
Colstrip Transmission System are contractually specified in the Colstrip Plant
Transmission Agreement ("CPTA") for each Colstrip Facility owner for each of
these segments, with the percentage ownership in the Colstrip-Broadview segment
of each of the Colstrip Facility owners approximating their aggregate ownership
share of the four generating units. MPC historically used its Colstrip Units 1
and 2 net capability to serve native loads located off its distribution system
at Broadview. Therefore, MPC's share of the Broadview-Townsend segment only
approximates its interest in Colstrip Units 3 and 4. The CPTA will remain in
effect for as long as energy is generated from the Colstrip Facility generating
units.
PPL Montana owns and operates the Hydroelectric Facilities, which include
eleven hydroelectric generating plants with a generating capability of
approximately 577 MW and one storage reservoir. The Hydroelectric Facilities are
licensed by the Federal Energy Regulatory Commission ("FERC") as four plants,
the Missouri-Madison Plants, the Thompson Falls Plant, the Kerr Plant and the
Mystic Plant. The Missouri-Madison Plants consist of the Hebgen Reservoir and
eight hydroelectric generating plants: Madison, Hauser, Holter, Black Eagle,
Rainbow, Cochrane, Ryan, and Morony. The Missouri-Madison Plants have a total
generating capacity of 291 MW. The Thompson Falls Plant consists of two dams,
the original intake and powerhouse at 36 MW and the Unit 7 powerhouse and intake
at 50 MW. The Kerr Plant has a total capacity of 189 MW and the Mystic Plant has
a total capacity of 11 MW.
The Corette Facility has a maximum net generating capability of 154 MW and
is a single operating coal-fired electric generating unit which is 100 percent
owned and operated by PPL Montana. The Corette Facility is primarily used by PPL
Montana to supply electricity to customers within the MPC service territory. In
1996, in order to meet the requirements of the Clean Air Act, the coal supply
for the Corette Facility was switched from the local Rosebud mine to a lower
sulfur coal from the Southern Powder River Basin of Wyoming. The primary source
of coal is supplied through a one-year contract with RAG Mining expiring
December 31, 2000 for 450,000 to 750,000 tons of 0.25 percent sulfur coal with a
heating value averaging 8,350 Btu/lb. A secondary source of coal is supplied
through a one-year contract with Decker Mining expiring December 31, 2000 for
100,000 to 200,000 tons of 0.25 percent sulfur coal with a heating value
averaging 9,200 Btu/lb. Each contract has a one-year renewal option. New
contracts with other Powder River Basin coal suppliers will be negotiated in
October 2000. Spot market purchases are also being considered.
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PPL Montana sells electricity to MPC under the terms of the Colstrip Unit
Number 3 Wholesale Transition Service Agreement dated December 17, 1999 (the
"MPC Colstrip Unit 3 Transition Agreement") and the Non-Colstrip Unit Number 3
Wholesale Transition Service Agreement dated December 17, 1999 (the "MPC
Non-Colstrip Unit 3 Transition Agreement" and, together with the MPC Colstrip
Unit 3 Transition Agreement, the "Wholesale Contracts"). The MPC Colstrip Unit 3
Transition Agreement has a term ending two years from the closing date, which
occurred on December 17, 1999. The MPC Non-Colstrip Unit 3 Transition Agreement
expires when MPC's remaining customer load is zero, but in no event later than
June 30, 2002. A portion of the generation from the Kerr Plant is sold to the
Flathead Irrigation Project ("FIP") under the terms of the Kerr FERC license.
During six months of the year, PPL Montana will be obligated to purchase 98 MW
generated by Basin Electric Power Cooperative ("Basin") under the terms of the
Basin Power Purchase Agreement (the "Basin PPA").
During the preparation of this Report, we reviewed the various agreements
related to the operation of the Plants to which PPL Montana is a party. These
agreements set forth the obligations of each of the parties with respect to
operation of the Plants. As Independent Engineer, we have made no determination
as to the validity and enforceability of the agreements; however, for the
purposes of this Report, we have assumed the agreements will be fully
enforceable in accordance with their terms and that all parties will comply with
the provisions of their respective agreements.
During the course of our review, we visited and made general field
observations of the Colstrip and Corette Facility and the Hydroelectric Facility
sites. The general field observations were visual, above-ground examinations of
selected areas which we deemed adequate to comment on the existing condition of
the sites but which were not in the level of detail necessary to reveal
conditions with respect to geological or environmental conditions; the internal
physical condition of any equipment; or the conformance with agreements, codes,
permits, rules, or regulation of any party having jurisdiction with respect to
the sites.
In addition, we have reviewed: (1) the status of permits and approvals and
compliance with those permits; (2) environmental assessment reports; (3) the
historic and projected levels of production of the Plants; (4) the historic
operating and maintenance expenses of the Plants; (5) historical operating
records of the Plants, and (6) operating programs and procedures.
DESCRIPTION OF THE MONTANA PORTFOLIO
COLSTRIP FACILITY
The Colstrip Facility is a four-unit, coal-fired, conventional steam cycle
electric generating plant. The Colstrip Facility is the second largest
coal-fired plant in the United States west of the Mississippi River. It is
located adjacent to the incorporated City of Colstrip, Montana which was
developed in the course of building the units. All four units have mine mouth
sub-bituminous coal supplied from the local Rosebud mines with coal supplied to
Colstrip Units 1 and 2 by truck and coal supplied to Colstrip Units 3 and 4 by
belt conveyor from the mine. Scrubbers are installed in the flue gas path from
each boiler to reduce emissions.
Colstrip Units 1 and 2 are identical electric generating units that have
been in commercial operation since 1975 and 1976, respectively. Each unit
consists of a single boiler and steam turbine generator ("STG") nominally rated
at 333 MW of gross generating capacity and approximately 307 MW of net
generating capacity, and can be dispatched down to 140 MW. The annual average
net plant heat rate is currently running approximately 11,100 Btu/kWh. Each unit
has a Combustion Engineering ("CE") pulverized coal-fired boiler and a General
Electric ("GE") STG.
Colstrip Units 3 and 4 are identical electric generating units that have
been in commercial operation since 1984 and 1986, respectively. Each unit
consists of a single boiler and STG nominally rated at 805 MW of gross
generating capacity and approximately 740 MW of net generating capacity, and can
be dispatched down to 200 MW. The annual average net plant heat rate is
currently running approximately 10,750 Btu/kWh for both units. Each unit has a
CE pulverized coal-fired boiler and a Westinghouse STG. In addition the Colstrip
Facility has certain common facilities shared by all four units, such as the
river pumping station and facility,
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coal handling facilities, a raw water surge pond structure and equipment,
reverse osmosis water treatment equipment, an environmental building,
warehouses, instrumentation and controls and machine shops, chemistry
laboratory, an administration building, an auxiliary services building,
garage/warehouse, and meteorological and air quality monitoring structures.
The Plant Site
The Colstrip Facility Site is located on unincorporated land in Rosebud
County, in southeastern Montana, adjacent to the City of Colstrip, along state
highway Route 39 (the "Colstrip Facility Site"). The site is easily accessible
and provides adequate access to necessary utilities and rail transportation. On
the basis of our observations and historical operation of the Colstrip Facility,
we are of the opinion that the site is suitable for the Colstrip Facility's
continued operation.
Approximately 3,100 acres of the Colstrip Facility is allocated to Colstrip
Units 1 and 2, approximately 2,664 acres is allocated to Colstrip Units 3 and 4,
and approximately 675 acres is land allocated to the common facilities. The
Colstrip Facility Site is bordered on the north by the City of Colstrip
municipal water tanks and wastewater treatment plant; on the south by state
highway Route 39; on the east by Western Energy's mine property; and on the west
by a park, two elementary schools and a residential area. There are two sets of
rail tracks into the site; one set of tracks enters the site from the west,
while the other set of tracks enters the site from the east. There is also a
mine haul road that enters the site from multiple directions and circles the
perimeter of the site, which also provide access for hauling bottom ash to the
effluent holding pond area for Colstrip Units 3 and 4.
Mechanical Equipment and Systems
Pulverized Coal-Fired Boilers
The Colstrip Units 1 and 2 boilers, which were manufactured by CE, are
identical controlled-circulation, radiant-reheat, outdoor types, designed for
balanced-draft operation. Each boiler includes a superheater, reheater,
economizer, two regenerative air preheaters, superheat and reheat
desuperheaters, and a soot blowing system. The boilers have a maximum continuous
rating of 2,520,000 pounds per hour ("pph") of superheated steam at 2,610 pounds
per square inch ("psig") and 1,005(LOGO)F. The boilers are designed to fire
pulverized coal as the primary fuel and to fire liquid petroleum gas ("LPG") for
start-up and low-load stabilization. In addition, each boiler's furnace has been
retrofitted with additional water deslagging capability above the burner
elevations. Each windbox assembly consists of a vertical-compartment housing
with five adjustable coal burner assemblies, a warm-up gas gun, three flame
detectors, four gas ignitors, two overfire-air ports, and thirteen secondary-air
compartments. New CE, low NO(X), concentric firing burners were installed on
Colstrip Units 1 and 2 boilers in the mid to late 1980's to lower firing
temperatures and reduce slagging.
There are five exhauster type coal mills for Colstrip Units 1 and 2, each
supplying a different elevation of coal nozzles and each unit can be maintained
full load with four mills in operation.
Primary and secondary air are provided to the boiler by two forced draft
fans, whose inlet air is heated by passing through steam-coil air preheaters to
maintain a constant fan discharge temperature and is then heated by passing
through the regenerative air preheaters. The heated air flows as primary air to
the coal mills and as secondary air to the boiler windboxes. Three induced draft
fans are provided to draw flue gas from the boiler, maintain a slight negative
pressure in the boiler and discharge to the inlet of the scrubber vessels.
The Colstrip Units 3 and 4 boilers, also manufactured by CE, are identical,
double-drum, forced-circulation, radiant-reheat, designed for balanced-draft
operation. The boilers are located indoors. Each boiler includes a superheater,
reheater, economizer, two regenerative air preheaters, superheat and reheat
desuperheaters, and a sootblowing system. Each boiler has a dual-furnace
separated by a division wall; each furnace has two air plenums that supply
secondary air to two windboxes mounted vertically at the corners of the furnace.
Each boiler fires pulverized coal as its primary fuel through eight elevations
of tilting tangential burners; each boiler fires No. 2 oil for start-up and
low-load stabilization. Each windbox supplies secondary air to eight burner
assemblies at the front and rear wall corners of the furnace. The burner
assemblies, which are
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arranged for tangential firing, are comprised of eight coal nozzles, fourteen
secondary air nozzles, two overfire air nozzles, six ignitors, one warm up gun,
and four flame scanners. Colstrip Units 3 and 4 have retained their original
burners and have reduced the flow of fuel air to meet NO(X) limits.
There are eight pressurized coal mills per Colstrip Units 3 and 4 boiler,
each supplies a different elevation of coal nozzles, and each unit can maintain
full load with seven mills in operation. Primary air is supplied to the mills by
two primary air fans. Secondary air, which passes through regenerative air
preheaters to the burner assemblies, is supplied by two forced-draft fans.
Glycol/steam air heaters are installed in inlets to the fan room to preheat
ambient air. Four induced draft fans draw flue gas from the boiler, maintain a
slight negative pressure in the boiler and discharge to the inlet of the
scrubber vessels.
Steam Cycle and Heat Rejection Systems
Each Colstrip Unit 1 and 2 boiler provides steam to its dedicated steam
turbine which are GE tandem-compound, double-flow, reheat, condensing,
two-cylinder turbines. Each turbine is rated at 332,922 kW at an inlet throttle
flow of 2,464,261 pph of steam at 2,400 psig, 1,000(DEGREES)F/1,000(DEGREES)F
reheat and 1.0 inch Hg absolute backpressure. It is equipped with an
electro-hydraulic-control and lube-oil equipment. The low-pressure section of
the steam turbine exhausts to a two-pass surface condenser, where the steam is
condensed by rejecting its heat to the circulating water system.
Each Colstrip Unit 1 and 2 circulating water system is a closed-loop system
that uses a wooden cross-flow induced draft-cooling tower. There are two 50
percent capacity, vertical circulating water pumps, which take suction from the
cooling tower basin and supply the condenser with cooling water which is
returned to the cooling tower. The cooling tower basins for Colstrip Units 1 and
2 are cross-connected to satisfy fire protection requirements. As an upgrade,
the cooling towers fill and drift eliminators have been replaced.
Boiler feedwater for each of Colstrip Units 1 and 2 is provided by three 50
percent capacity steam-turbine-driven condensate pumps, two 50 percent capacity
boiler feed booster pumps and two 50 percent capacity boiler feed pumps through
six stages of feedwater heating including a deaerator. Each unit's high pressure
feedwater heaters 4 and 5 have been retubed with stainless steel.
Each Colstrip Unit 3 and 4 boiler provides steam to its dedicated steam
turbine which is a Westinghouse tandem-compound, single-reheat, regenerative,
four-flow condensing turbine rated at 805,000 kW at a throttle flow of 5,800,000
pph of steam at 2,400 psig, 1,000(DEGREES)F/1,000(DEGREES)F reheat and a
backpressure of 2.5 inches Hg absolute. The two Colstrip Unit 3 low pressure
steam turbine sections were replaced in 1995 with a "ruggedized" design which
increased the last stage blade length from 30 to 31 inches and also increased
power output. Colstrip Unit 4 low pressure steam turbine sections were similarly
replaced in 1996. The low-pressure sections of the steam turbine exhaust to a
dual pressure condenser where the steam is condensed by rejecting its heat to
the circulating water system. Each steam turbine is equipped with an
electro-hydraulic control fluid system and lube-oil equipment.
Each Colstrip Unit 3 and 4 has a closed-loop circulating water system and a
circular concrete, counter-flow induced draft-cooling tower. Circulating water
flows by gravity flow from the tower basin to the circulating water pumphouse
that houses the circulating water pumps for both units. There are two vertical
circulating water pumps for each unit that circulate water to each unit's
condenser and return it to the cooling towers.
Boiler feedwater for each Colstrip Unit 3 and 4 is provided by three 50
percent capacity condensate pumps, two 50 percent capacity boiler feedwater
booster pumps and two 50 percent capacity boiler feed pumps. Each booster pump
is paired with a feed pump and both are driven by a common steam turbine. There
are seven stages of feedwater heating including a deaerator.
Fuel Handling Systems
Coal is supplied by truck to Colstrip Units 1 and 2 from Area D of the
Western Energy Rosebud Mine. Coal handling systems transfer coal from the mine
storage pile to the coal silos located at the units. Coal is gravity fed from
beneath the mine storage pile to eight in-line hoppers, which discharge through
a Rex Carrier
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vibratory feeder onto a conveyor belt. The vibratory feeders have a variable
capacity up to 250 tons per hour ("tph"). Coal then travels along conveyors
through a series of sampling, weighing, and blending equipment before being
deposited on the surge pile. The conveyors are equipped with protective devices,
including stop switches, belt misalignment switches, critical speed switches and
belt take-up switches. From the surge pile, the coal is gravity fed onto two
coal conveyors. The conveyors discharge the coal into a common Colstrip Unit 1
and 2 distribution bin; the coal is then distributed via belt conveyors to ten
coal silos (five per unit). The coal handling system is equipped with a dust
collection system at the conveyor discharge points, and there is also a dust
suppression system at the surge pile. LPG is normally transported to the site by
truck. The LPG system consists of six storage tanks, each with a capacity of
52,500 gallons.
The primary source of coal to Colstrip Units 3 and 4 is from Area C of the
Western Energy Rosebud Mine. Coal is delivered from the mine to the units via a
4.25-mile long belt conveyor. From the belt conveyor, the coal passes through
sampling and weighing equipment to the covered live-storage coal facility. From
the surge pile, the coal travels along conveyors to a common distribution bin
from which a series of drag chain conveyors supply the eight coal silos at each
of the units. The coal handling system is equipped with a dust collection system
at conveyor discharge points. No. 2 oil used for start-up fuel for Colstrip
Units 3 and 4, is stored in one of two above-ground 500,000-gallon fuel oil
tanks equipped to receive oil by truck or rail. Presently, one tank is in
service, while the other has been retired in place. A study is underway to
determine if it is economical to return it to service.
Ash Handling Systems
Bottom ash and slag that fall to the bottom of the furnace section of each
of the boilers at the Colstrip Facility are collected in water-sealed refractory
lined hoppers. Colstrip Units 1 and 2 boilers each have two hoppers and Colstrip
Units 3 and 4 boilers have three hoppers each. A clinker grinder at the outlet
of each hopper crushes large pieces of bottom ash so they can pass through the
conveying system. Ash sluice pumps discharge the ash slurry to a transfer tank,
which also collects ash from the economizer hoppers, and pyrites from the coal
mills. The combined slurry is further pumped to a bottom ash pond. The bottom
ash pond is divided into separate sections to allow the ash to settle. Residual
water is stored in the clearwell portion of the ash pond, from where it is
pumped to the bottom ash system return header which supplies the suction of the
three high-pressure ash sluice pumps dedicated to Colstrip Units 1 and 2 and
three pumps dedicated to Colstrip Units 3 and 4.
Make-Up Water System
Originally Colstrip Units 1 and 2 boiler makeup water was produced by
evaporators and two ion-exchange demineralizer trains. In 1998, the Colstrip
Units 1 and 2 evaporators and demineralizers were decommissioned and replaced
with reverse osmosis units preceded by pressure filter pretreatment, which in
conjunction with the Colstrip Unit 3 and 4 demineralizer trains now supply all
condensate make-up required by the Colstrip Facility.
Additional Structures and Systems
There is an auxiliary boiler for Colstrip Units 1 and 2 which was designed
to supply steam during start-up and emergencies. However, it has not been used
for several years and is currently not functional. Steam for start-up and
emergency operations is provided from either of the four main boilers.
Colstrip Units 1 and 2 compressed air can be supplied by three air
compressors, one of which is a one-third sized spare. Air for instrument
services is processed through either of two desiccant air dryers.
Structures and systems that are shared by both Colstrip Units 1 and 2
include: the control room, LPG system, yard coal handling, flyash ponds A and B,
evaporation ponds, bottom ash pond, auxiliary boiler, spare main transformer, a
condensate polishing demineralizer system and the emergency diesel generators.
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Colstrip Units 1 and 2 each have a 500-foot, reinforced-concrete, steel
lined chimney with a diameter of 16.5 feet. Testing enclosures at the 250-foot
elevation house the Continuous Emissions Monitoring System ("CEMS") and stack
testing ports.
A motor-driven fire pump takes suction from the Colstrip Unit 2 cooling
tower basin and a diesel engine-driven fire pump takes suction from the Colstrip
Unit 1 cooling tower basin. A motor-driven jockey pump which takes suction from
the raw water supply header maintains fire water system pressure.
Colstrip Unit 3 and 4 include a heating boiler located in the auxiliary
service building that can supply saturated steam to the plant space-heating
system, but it has been laid-up dry and is currently not used.
For Colstrip Unit 3 and 4, a diesel engine-driven fire pump and a
motor-driven jockey pump take suction from a common fire pump basin. The
computer room and telephone equipment room are protected by Halon systems. Halon
is being replaced with alternative material as the current inventory of Halon is
used. Compressed air for both units is supplied by five air compressors. Air for
instrument service is processed through either of four desiccant air dryers.
Structures and systems that are shared by both Colstrip Units 3 and 4
include: the control room; fuel oil tanks, yard coal handling, effluent holding
pond, circulating water pumphouse, bottom ash ponds, lime handling, plant
heating boiler, emergency diesel generators, spare main transformer, condensate
polishing demineralizers and make-up demineralizer.
Colstrip Units 3 and 4 each have a 692-foot, reinforced-concrete, steel
lined chimney with a diameter of 24 feet. Testing enclosures at the 379-foot
elevation house the CEMS and stack testing ports.
Electrical and Control Systems
Each of the Colstrip Units 1 and 2 steam turbines drives a GE
hydrogen-cooled generator rated 377 MVA at 0.95 power factor, 22 kV, with
water-cooled stators and Generex static excitation systems. Each of the Colstrip
Unit 3 and 4 steam turbines drives a Westinghouse hydrogen-cooled generator
rated 819 MVA at 0.95 power factor, 26 kV, with water-cooled stators and
shaft-driven brushless excitation systems.
The Colstrip Unit 1 generator was completely rewound in 1994. Top stator
bars in the Colstrip Unit 2 generator have been replaced, and a complete rewind
of the generator is under consideration. Cooling water piping connections to
these units have been a continuing problem, which is controlled by preventive
maintenance during each outage. One of the Colstrip Units 3 and 4 generator
rotors was replaced in 1993. The removed rotor was refurbished and installed in
the other unit in 1996. The second removed rotor now serves as a spare.
Each generator is connected through isolated phase bus duct to its main
generator step-up transformer. Colstrip Units 1 and 2 utilize three-phase
outdoor oil-filled units rated 21.4-230 kV, 374 MVA with forced oil/ forced air
cooling. Colstrip Units 3 and 4 are provided with single-phase outdoor
oil-filled units rated 26-525 kV, 280 MVA with forced oil/forced air cooling
(840 MVA per three-phase bank). One spare main generator step-up transformer for
Colstrip Units 3 and 4 is on-site.
On September 26, 1999, the Colstrip Unit 1 generator step-up transformer
experienced a sudden failure, resulting in a major oil release and fire. The
failure of the step up transformer is believed to have been initiated when a
support structure failed on the 230 kV transmission line less than two miles
from the Colstrip Facility. The fire also damaged the adjacent Colstrip Unit 1
start-up transformer and nearby auxiliary equipment. Both Colstrip Units 1 and 2
tripped off line at the time of the failure. Fire damage was limited by the
activation of the fire suppression sprinkler system on the step-up transformer,
and by the plant's fire brigade and the local fire department. Restoration
efforts began immediately after the fire was extinguished. Colstrip Unit 2 was
returned to service in approximately one week, following the repair of fire
damaged cabling and the testing of the unit's transformers and generator.
Colstrip Unit 1 was returned to service approximately one week later following
the replacement of the damaged step-up and start-up transformers with spare
transformers that were available on site, the testing of the generator, and the
repair of the damaged electrical cabling, circuit breakers, and other auxiliary
equipment. The failed Colstrip Unit 1 generator step-up transformer has been
scrapped
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and a new transformer has been ordered and is expected to be delivered in August
2000. The damaged start-up transformer has been repaired and placed back in
service. MPC provided a spare step-up transformer which is on-site.
On the high side of each main generator step-up transformer, a short
overhead line connects to the Colstrip 230 kV or 500 kV switchyard. The
generation point of receipt is defined as the point of connection to the 230 kV
bus for Colstrip Units 1 and 2, and the point of connection to the 500 kV bus
for Colstrip Units 3 and 4. The overhead lines connecting the generator step-up
transformers and start-up transformers to the switchyards are included in the
Montana Portfolio, as are the two circuit breakers and associated disconnect
switches which connect each generator circuit to the switchyard buswork.
The Colstrip Facility auxiliary power is derived from the generator
circuits with start-up power derived from the nearby Colstrip 115 kV switchyard.
The auxiliary transformers are outdoor, oil-filled units. Colstrip Units 1 and 2
are equipped with three-winding, three-phase outdoor oil-filled units rated
21-7.2-7.2 kV, 48 MVA. Colstrip Units 3 and 4 are provided with three-winding,
three-phase outdoor oil-filled units rated 26-13.8-4.16 kV, 100 MVA.
Auxiliary start-up power is supplied from the Colstrip 115 kV switchyard.
Colstrip Units 1 and 2 share a common three-phase outdoor oil-filled transformer
rated 115-7.2 kV, 42 MVA. Colstrip Unit 3 is equipped with a three-phase,
three-winding outdoor oil-filled transformer rated 115-13.8-4.16 kV, 50 MVA. The
Colstrip Unit 4 start-up transformer is identical to the Colstrip Unit 3
transformer. The spare start-up transformer for Colstrip Units 1 and 2, rated
115-7.2 kV, 20 MVA, is available on-site, as discussed above.
To improve the voltage on the auxiliary systems during start-up of Colstrip
Units 3 and 4, a dedicated 230-115 kV autotransformer was added in the
switchyard. This autotransformer, included in the Montana Portfolio, can also
supply the start-up transformer for Colstrip Units 1 and 2.
The points of interconnection for the start-up circuits are the termination
of the 115 kV circuit in the switchyard, and the bus-side disconnects for the 23
kV circuit breakers on the high side of the 230-115 kV start-up autotransformer.
The two 230 kV circuit breakers (designated 230-20 and 230-64) and
associated disconnect switches on the high side of the start-up 230-115 kV
autotransformer are included in the Montana Portfolio, as are the two 115 kV
circuit breakers (designated 100-202 and 100-204) and associated disconnect
switches on the low side of the autotransformer. No other substation facilities
are included.
Colstrip Units 1 and 2 medium voltage switchgear is the air-magnetic type.
About half of the breakers have been converted to vacuum interruption using the
original breaker truck and mechanism. Colstrip Units 3 and 4 have vacuum-type
medium voltage switchgear.
Numerous 7.2 kV-480 V, 13.2 kV-480 V and 4.16 kV-480 V indoor dry-type
transformers located throughout the Colstrip Facility, as well as several
outdoor oil-filled transformers, provide low voltage power for smaller motors
and miscellaneous plant loads. Lighting transformers are connected to the 480
volt systems for lighting and general power requirements.
AC and DC Critical Systems
Colstrip Units 1 and 2 each include a 125 volt battery system for critical
DC loads. Each battery has a dedicated charger, and a third charger can be used
as backup for either battery.
Colstrip Units 3 and 4 are each provided with three 125 volt battery
system, with battery chargers arranged as for Colstrip Units 1 and 2 so there is
one spare for each two batteries. In addition, a 125 volt battery with two
chargers powers critical scrubber loads. There are also two 250 volt battery
systems, one each for Colstrip Units 3 and 4, for DC oil pumps. The 250 volt
charger arrangement is similar to the 125 volt arrangement, with a total of
three chargers.
Critical AC loads are provided with dedicated uninterruptible power systems
("UPS"). These loads include flame safety systems, turbine controls, and the
plant computers.
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In addition, diesel generators can supply critical and important AC loads
including turning gear if all external power is lost for an extended period. Two
Delco 600 kW 480 volt generators are provided for Colstrip Units 1 and 2, and
four 1000 kW 4.16 kV generators are provided for Colstrip Units 3 and 4. The
Colstrip Facility does not have black start capability.
The Colstrip Facility communications system for Colstrip Units 1 and 2 is a
typical Gai-Tronics page-party public address/telephone system. Colstrip Units 3
and 4 are equipped with a PAX telephone system. Radios are used to supplement
the Gai-Tronics and PAX systems.
Plant Control System
The boiler-turbine-generator control systems include analog and digital
dedicated controls, with some programmable logic controllers ("PLC") for
specific systems. Colstrip Units 1 and 2 include Westinghouse Series 7300 boiler
controls and GE Mark I turbine controls, with a Fischer and Porter 3000 plant
computer for alarm and data logging. Colstrip Units 3 and 4 utilize Westinghouse
Series 7300 boiler controls and Westinghouse DEH turbine controls together with
a Westinghouse Series 2500 plant computer. Scrubber controls for all four units
are implemented in Allen-Bradley PLCs. Colstrip Units 1 and 2 do not include
hardware necessary for automatic dispatch, but Colstrip Units 3 and 4 are so
equipped.
Environmental Control System and Equipment
Air Emissions
The Colstrip Facility's Title V Air Operating Permit contains air emission
limits for the key pollutants of particulate matter, SO(2), NO(X) and opacity.
The basic air pollution control technologies employed at the Colstrip Facility
to control the aforementioned pollutants are a SO(2) desulfurization system
(scrubber), and low-NO(X) burners for the control of NO(X) emissions. The
scrubbers are of a high-energy type that also controls the emissions of
particulate matter.
Colstrip Units 1 and 2 are each equipped with a flue gas scrubber unit;
each unit has three vessels, which are 70 feet tall by 35 feet in diameter, and
all three vessels are needed for full load operation. The scrubber is designed
to meet 75 percent SO(2) removal and 99.5 percent particulate matter removal.
Each scrubber vessel is supplied with a reheater to raise the flue gas
temperature above the dew point. In the venturi section of the scrubber vessels,
flue gas is accelerated to increase gas velocity for thorough mixing with the
slurry and fly ash particles are entrained with the fly ash slurry. All interior
components of the scrubber vessels have a protective coating to inhibit
corrosion and erosion, and eight emergency water sprays are located at the inlet
of each scrubber vessel. Emergency sprays are automatically placed in service in
the event of high scrubber inlet or outlet temperature or low upper and middle
spray flows. The slurry recycle system circulates the slurry from the scrubber
recycle tank to the venturi and absorption sprays. Three centrifugal recycle
pumps per vessel supply the slurry to the upper and lower sprays on each
scrubber vessel. Three scrubber pond return pumps supply return water from the
fly ash pond clearwell to the scrubbers of both Colstrip Units 1 and 2.
Colstrip Units 3 and 4 are each equipped with eight stainless steel
scrubber vessels (six vessels are required for full load). The scrubber unit is
designed for 95 percent SO(2) removal and 99.5 percent particulate matter
removal. Each scrubber vessel consists of five main sections: the venturi-spray,
absorption-spray, wash tray, mist eliminator, and recycle tank sections. Most
fly ash and some SO(2) are removed from the flue gas in the venturi section,
while the absorption sprays remove additional SO(2). The wash trays and mist
eliminators remove liquid entrainment. High calcium lime is added to maintain
proper pH. The stainless steel scrubber recycle tanks, which were manufactured
by Union Boiler, are each 35 feet diameter and 17 feet high with a capacity of
100,000 gallons. For each scrubber, slurry is pumped to the venturi sprays by
two 100 percent capacity Warman centrifugal pumps; each pump discharges 6,700
gpm at a head of 110 feet and are belt-driven by 400 hp, 4,160 volt motors. The
absorption sprays are supplied by two 100 percent capacity pumps. The scrubber
system is also supplied with a reheating system containing eight total
reheaters, one per scrubber vessel. The reheaters are provided as the flue gas
leaves each scrubber vessel to prevent condensation in the ductwork, induced
draft fans, and stack.
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Effluent from the scrubbers is pumped to an effluent holding pond located
three miles southeast of the Colstrip Facility Site. The pond has a surface area
of 337 acres and a volume of 17,200 acre-feet. Water that separates from the
effluent is returned to the plant for use in the scrubbers.
NO(X) emissions were improved by the low-NO(X) burners which were
retrofitted on Colstrip Units 1 and 2 primarily for the control of slagging.
Although no retrofits were made to the Colstrip Units 3 and 4 burners,
modifications to the overfire air were made that allowed the units to achieve
comparable emission rates as Colstrip Units 1 and 2. All four units employ
separated overfire air for the control of NO(X) emissions. The units achieve
emission rates in the 0.35 to 0.45 lb/MMBtu range on a routine basis. Such rates
are in compliance with the limits set forth in the Operating Permit and in
compliance with the NO(X) limits set forth in the Title IV Acid Rain Permit.
Colstrip Units 1 and 2 are equipped with CEMS, which include SO(2), NO(X),
opacity, CO(2) and flow monitoring systems. The SO(2), NO(X), flow and opacity
monitors are of the in-situ type.
Colstrip Unit 3 and 4 are equipped with SO(2), NO(X), opacity, CO(2) and
flow monitoring systems. The SO(2), and NO(X) monitors are of the extractive
type measuring and reporting concentrations on a dry basis. The opacity and flow
monitors are of the in-situ type. The SO(2), and NO(X) analyzers for Colstrip
Units 3 and 4 were replaced during 1999. Also, the Data Acquisition System for
the Colstrip Facility was upgraded in 1999.
The CEMS were upgraded in 1995 and, along with the 1999 upgrades including
the data acquisition system and flow monitors, meet the 40 CFR Part 75
monitoring regulations.
Wastewater/Solid Waste Disposal
The Colstrip Facility is permitted as a zero discharge wastewater facility.
The solid waste generated at the facility, namely, scrubber sludge with fly ash,
and bottom ash, is disposed of on-site in a series of ponds and disposal areas.
Likewise, the wastewater involved in the operation of the scrubber, the cooling
towers, other plant processes, and transportation of the bottom ash to the
disposal ponds is disposed of in a series of ponds.
Bottom ash from Colstrip Units 1 and 2 is wet sluiced from the boilers to
the bottom ash pond. The ash is allowed to settle and the sluice water is stored
in the clear well part of the pond and then returned to the plant for reuse.
Settled bottom ash from the bottom ash pond is excavated and trucked to the
effluent holding pond area for Colstrip Units 3 and 4.
Fly ash and scrubber sludge from the scrubber of Colstrip Units 1 and 2 is
piped to Fly Ash Ponds A and B. Fly ash and scrubber sludge is allowed to settle
with the water returned to the scrubbers via the Fly Ash Pond clear well. The
settled material is transported via pipeline to the Colstrip Units 1 and 2
effluent holding ponds located approximately two miles northwest of the plant
area for final disposal. The Colstrip Units 1 and 2 effluent holding pond area
consists of three ponds. Stage I which is inactive and Stage II which is
comprised of two ponds. The Stage II ponds are used to store effluent which then
flows to the clear well and returned to the plant for reuse in the scrubber
system.
Cooling tower blowdown from Colstrip Units 1 and 2 is directed to Pond C
South. From there the blowdown is recycled back to the scrubber to be used for
scrubber make-up. The adjacent Pond C North, which was used for cooling tower
blowdown collection, is now inactive.
Bottom ash from Colstrip Units 3 and 4 is wet sluiced to a series of six
Bottom Ash Ponds. Settling of solids occurs in the ponds and the effluent
discharges to an adjacent clearwell for recycling to the plant. Bottom ash is
excavated and trucked to the Colstrip Units 3 and 4 effluent holding pond area.
Fly ash and scrubber sludge are sluiced to the Colstrip Units 3 and 4
effluent holding pond area located approximately three miles southeast of the
plant area. The slurry is deposited into the ponds for settling of suspended
solids. The clarified effluent flows to a clearwell from where it is recycled to
the plant scrubber system. The effluent holding area is divided into several
cells which allows for sediment in all areas of the pond to be periodically
dewatered.
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In total there are 26 ponds at the Colstrip Facility Site. There are eleven
ponds for Colstrip Units 1 and 2, eleven ponds for Colstrip Units 3 and 4, two
common ponds, and two sedimentation ponds. Of these ponds, ten ponds are
presently inactive.
Off-Site Requirements
All four Colstrip units are currently burning a low sulfur coal from the
Western Energy Rosebud Mine approximately 6 miles from the Colstrip Facility.
Colstrip Units 1 and 2 coal is supplied by truck from Area D of the mine.
Colstrip Units 3 and 4 coal is supplied via a 4.25-mile long belt conveyor from
Area C. Colstrip Units 1 and 2 utilize LPG as a start-up fuel while Colstrip
Units 3 and 4 use No. 2 fuel oil. LPG and No. 2 fuel oil are shipped by truck to
the Colstrip Facility Site.
The Colstrip Facility electric output is interconnected to the MPC grid at
230 kV and to the Colstrip Transmission System at 500 kV. Startup power is
obtained from the MPC grid at 115 kV and 230 kV. There are two 500 kV
transmission lines, one 230 kV transmission line, and one 115 kV transmission
line leaving the switchyard complex. In addition, a 115-69 kV autotransformer
serves local MPC and cooperative loads, and two 115 kV positions serve
distribution circuits.
Raw water for all four Colstrip units is obtained from the Yellowstone
River pumping plant, which is located near Forsyth, Montana on the Yellowstone
River. The claimed water rights are 250 cubic feet per second ("cfs"), but
presently only 66 cfs is used at the Colstrip Facility, of which 20 cfs is
allocated to Colstrip Units 1 and 2, 44 cfs to Colstrip Units 3 and 4 and 2 cfs
to the Colstrip community. Three pumps discharge water from an intake channel
into two pipelines, each of which are approximately 30 miles long. A spare pump
is available, but not installed. The two pipelines deliver water to a surge
pond, Castle Rock Lake, that provides 26 days of winter storage capacity for the
four units and the City of Colstrip. The surge pond dam is an earth-fill
embankment with a concrete spillway. The water is pumped from the surge pond to
the Colstrip Units 1 and 2 makeup clarifier and to Colstrip Units 3 and 4 raw
water system. Raw water to be used as potable water by the City of Colstrip and
the Colstrip Facility is processed by a primary water treatment plant owned by
the City of Colstrip. Both the water treatment and wastewater treatment plants
have been owned and operated by the City of Colstrip since late 1999. The entire
station is operated as a zero-discharge facility for wastewater.
There are also two separate lime-unloading stations provided for delivery
of lime to Colstrip Units 3 and 4 scrubbers. A railcar unloading station
utilizes a vacuum/pressure conveying system to transport lime to the storage
silos. A truck unloading station connects to a manifold that also carries lime
to the silos.
Review of Technology
The design and construction of electric utility boilers burning pulverized
bituminous coal in suspension in a water-cooled furnace became common in the
1930's. This technology has been utilized extensively for coal fired generating
stations above 100 MW for over 40 years. Sustained combustion of pulverized coal
is dependent on its having medium to high level of volatility. The fineness to
which the coal must be ground is in turn dependent upon the volatility of the
coal and the ease with which a coal can be ground, its grindability, is
dependent upon its hardness. The grindability affects the design of and power
required to operate the mills used to pulverize the coal. The ash content of the
coal is important as 80 percent of the ash contained in the fired coal is
carried out of the boiler as "fly ash" by the flue gas, the remaining 20 percent
falls and is collected in the bottom of the furnace. By today's environmental
standards over 99 percent of this fly ash must be removed from the flue gas and
collected. Other chemical constituents of the coal are also important. Sulfur
directly affects the quantity of environmentally sensitive SO(2) that is
produced and emitted. Sodium in conjunction with other chemicals affects the
temperature at which the ash becomes fluid and hence prone to collecting on
cooler furnace and tube surfaces where it hardens and builds up as slag. Slag
adversely affects boiler performance by reducing heat transfer surface,
restricting gas flow passages and can do damage when a large piece breaks free
and falls onto the bottom of the furnace. Formation of slag is a common
experience on many coal-fired power plants and, as on the Colstrip and Corette
Facilities, is addressed and dealt with by the operators. All of the Colstrip
units use a wet lime, high energy type scrubber to remove SO(2) and particulates
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from the flue gas stream. This type of technology is proven and has been used
for similar applications on plants of this type for approximately the past 20
years.
In general, Colstrip Units 1, 2, 3 and 4 have been normally base loaded.
Colstrip Units 3 and 4 boilers have been normally run at 5 percent overpressure
while Colstrip Units 1 and 2 are not. Colstrip Units 1 and 2 are manually
dispatched by PPL E-Plus in Butte, Montana. Colstrip Units 3 and 4 have the
ability to accept an automatic dispatch signal. Colstrip Units 1 and 2 must
reduce load to 230 MW each to permit scrubber maintenance as there is no spare
scrubber vessel capacity, while Colstrip Units 3 and 4 have spare capacity that
allows routine scrubber maintenance without reducing loads on the units.
Based on discussions with PPL Montana operating and maintenance personnel
and review of operating reports for the past five years, it appears that the
steam turbines' output is limited by copper buildup. Copper carryover is
believed to originate from the feedwater heater tubing copper alloy material.
The feedwater carries the copper to the boiler where it vaporizes with the steam
and is deposited on the boiler steam passes and steam turbine blades. Plant
start-up procedures have been adjusted to reduce copper carryover and some
feedwater heater tube material has been changed to stainless steel alloy.
Feedwater chemical treatment has also been changed as it has been found to
contribute to copper carryover. The recent revision to reverse osmosis units for
make-up water treatment may contribute to a reduction in copper carryover. To
reduce the sources of copper, PPL Montana will continue to replace the existing
feedwater heaters, which have tubes made of cuprous alloys, with stainless steel
tubed heaters. Funding for the replacement of feedwater heaters is included in
the capital expenditures budget for 2000 to 2003 for Colstrip Units 1 and 2 and
Colstrip Units 3 and 4. The copper coating on the blades can be removed by foam
cleaning of the steam turbines. It has been successfully performed on Colstrip
Units 3 and 4, but in the case of Colstrip Units 1 and 2, turbine seals have to
be changed from a copper alloy to stainless steel to avoid damaging the seals in
the cleaning process. PPL Montana has advised that the Colstrip Unit 1 turbine
seals were replaced in 1999 and the Colstrip Unit 2 turbine seals are scheduled
to be replaced in 2002. An extension in the period between turbine outages is
expected as a result of this change.
The Colstrip Unit 1 and 2 boilers' furnaces are acknowledged to be
undersized for the type coal being burned and as a result these units have a
history of heavy slagging occurring on tube surfaces in the furnaces. Colstrip
Units 3 and 4 furnaces are relatively larger and hence experience less problems
with slagging. All four units are subject to load reductions to deslag the
boilers. Intensive soot blowing, used to release slag and maintain optimum heat
transfer surface, tends to damage tubes. Reheater tubes on Colstrip Units 1 and
2 were replaced in the 1993 to 1994 time period due to damage caused by soot
blowing and high temperatures. Crash bars have been installed on tubes in
critical areas below burners to reduce potential damage to the tubes from
falling slag clinkers. At times when the boilers are shut down, mechanical
techniques including explosive charges must be used to dislodge the slag. Large
particles of slag carried over by the flue gas to the economizer tended to be
caught in the fin tubes which reduced gas flow and lowered the economizer's
performance. The Colstrip Unit 2 economizer was replaced in 1992 with a
different design that does not plug. Colstrip Unit 1 economizer is being
evaluated for a full or partial replacement in 2001. Colstrip Units 3 and 4 have
not reported any economizer problems. Colstrip Units 1 and 2 boiler arches have
both been replaced.
Based on our review, we are of the opinion that the Colstrip Facility has
been designed and constructed in accordance with good engineering practices and
generally accepted industry practices and the technology in use at the Colstrip
Facility is a sound, proven conventional method of electric generation.
Furthermore, all major off-site requirements of the Colstrip Facility are
adequately provided for, including coal supply, water supply, and electrical
interconnections. If operated and maintained as they are currently, the Colstrip
Facility should be capable of meeting the currently applicable environmental
permit requirements.
Availability
PPL Montana has advised that, with assistance from its parent company in
Allentown, Pennsylvania, it is continuing to improve its outage management
practices at the Colstrip Facility to reduce the amount of scheduled outage time
required. Outages are to be scheduled based on the condition of a piece of
equipment rather than the amount of time in service since its last outage. The
condition of equipment, and hence the need
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for overhaul or internal inspection, is to be determined by the more extensive
use of predictive maintenance techniques. While this practice is expected to
extend the normal period between equipment outages for many pieces of equipment,
reliability concerns with the Colstrip Units 3 and 4 boilers have resulted in
reducing the period between major outages from three to two years. PPL Montana
has advised that it intends to make better use of established unit outage
management practices under which it is prepared to pursue scheduled outage
repairs, inspections and overhauls during periods of forced outages whenever the
forced outage periods are to be greater than that required for the scheduled
outage activities. This approach should reduce the number of activities required
to be performed during a scheduled outage. Based on historical performance data
from the Colstrip Facility, review of current and proposed operations and
maintenance practices and procedures and general observation of the Colstrip
Facility, we are of the opinion that the Colstrip Units 1, 2 3 and 4 should be
capable of achieving projected annual average equivalent availability factors of
87.9, 84.9, 88.7 and 86.3 percent, respectively, over the term of the
Certificates. There will be years when the availability factor is both above and
below the projected annual average.
Estimated Useful Life
We have reviewed the quality of equipment installed at the Colstrip
Facility, the general plans for operating and maintaining the facility and the
performance of the Colstrip Facility. On the basis of this review and assuming
that: (1) the units are operated and maintained in accordance with the policies
and procedures as presented by PPL Montana, (2) all required renewals and
replacements are made on a timely basis as the units age, and (3) coal, gas and
oil burned by the units are within the expected range with respect to quantity
and quality, we are of the opinion that the Colstrip Facility should have a
useful life extending well beyond the term of the Certificates.
COLSTRIP TRANSMISSION SYSTEM
Description of the Colstrip Transmission System
The Colstrip Transmission System includes two 500 kV AC transmission lines
from the Colstrip 500 kV Switchyard to the Broadview Substation, two 500 kV AC
transmission lines from the Broadview Substation to Townsend, Montana, the
Colstrip 500 kV Switchyard (except for those facilities included with the
generating units) and the 500 kV facilities at the Broadview Substation.
The "A" line in the Colstrip -- Broadview segment was originally
constructed as a double-circuit 230 kV line for future conversion to
single-circuit 500 kV. It was constructed around 1970. The remaining lines ("B"
in the Colstrip -- Broadview and "1" and "2" in the Broadview -- Townsend
segments) were constructed as 500 kV single-circuit lines in the 1982 to 1983
time period.
The two transmission lines in each segment are located on the same
right-of-way over most of the route. The Colstrip -- Broadview segment line
length is approximately 115 miles and the Broadview -- Townsend segment is
approximately 133 miles. The lines continue west of Townsend under BPA ownership
as a double circuit line to Garrison, Montana. Table 1 summarizes the current
and pending ownership interests in the Colstrip Transmission System.
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TABLE 1
OWNERSHIP ENTITLEMENT IN THE COLSTRIP TRANSMISSION SYSTEM
(MW)
COLSTRIP-BROADVIEW BROADVIEW-TOWNSEND
----------------------------- -----------------------------
CURRENT OWNERSHIP PPL MONTANA OWNERSHIP PPL MONTANA
OWNER ENTITLEMENT ACQUISITION(1) ENTITLEMENT ACQUISITION(1)
- ------- ----------- -------------- ----------- --------------
MPC...................................... 822.8 612.8 468.5 258.5(2)
Puget.................................... 746.0 0.0 758.6 0.0
Portland................................. 307.2 0.0 312.4 0.0
AVISTA................................... 230.4 0.0 234.3 0.0
PacificCorp.............................. 153.6 0.0 156.2 0.0
------- ----- ------- -----
Total.................................... 2,260.0 612.8 1,930.0 258.5
- ---------------
(1) -- Based on PPL Montana's contingent contract to purchase MPC's Colstrip
Units 1, 2 and 3 ownership interests in the Colstrip Transmission System.
(2) -- MPC granted BPA the right to utilize 48.5 MW of its interest in the
Broadview-Townsend capability in exchange for a reduction in facility use
charges, resulting in 210 MW of net available capability on this segment of
the Colstrip Transmission System.
PPL Montana has a contingent contract to purchase the ownership and
contractual interests related to 74.5 percent of MPC's entitlements in the
Colstrip-Broadview segment and 55.2 percent of MPC's entitlements in the
Broadview-Townsend segment of the Colstrip Transmission System. These ownership
percentages correspond to an approximate 50 percent capacity share of Colstrip
Units 1 and 2, a 30 percent capacity share of Colstrip Unit 3 on the
Colstrip-Broadview segment, and a 30 percent capacity share of Colstrip Unit 3
on the Broadview-Townsend segment. MPC has retained its remaining interest in
the Colstrip Transmission System which provides transmission capacity for its
Colstrip Unit 4 interest, and is remaining as operator of the Colstrip
Transmission System.
MPC has retained ownership of certain parts of the Broadview 500 kV
Switchyard, including two thirds of the autotransformers and two ninths of
common facilities including circuit breakers, buswork, control house, warehouse,
and common equipment in the control house.
Transmission line electrical ratings are 550 kV maximum; 2,000 amps
continuous; and 2,200 amps for one hour emergency. The current ratings are based
on series capacitor bank and wavetrap ratings, and could be increased to 3,000
amps continuous and 3,300 amps emergency with modifications to the capacitor
banks and replacement of the "A" line wavetraps only. Conductor thermal ratings
are approximately 4,800 amps per line.
The transmission line structures are lattice galvanized steel, with a
majority of the tangent structures being guyed. Angle and deadend structures and
those located where sufficient guying space was not available are
self-supporting. Guyed structures utilize four guys positioned at angles of 45
degrees from the centerline, with anchors set in concrete. Overall structure
heights vary from about 100 feet to 170 feet. There are approximately four
structures per mile except where geography or routing required additional
structures for angles or to maintain ground clearance. Structures are erected on
concrete foundations designed for the soil conditions at the structure location.
Structures are designed for National Electric Safety Code heavy loading,
with additional requirements for heavy horizontal wind, heavy wind and ice
combination, heavy vertical loading, balanced longitudinal loading (next
structure down, all wires intact), unbalanced longitudinal loading (ice
dropping), unbalanced vertical loading (ice dropping), and construction and
maintenance loads. Wind and ice loading criteria were determined from a local
meteorological study and based on a 50-year storm.
Phase conductors are bundled aluminum conductor, steel reinforced ("ACSR")
supported on toughened glass insulator strings. Overhead ground (shield) wires
are Alumoweld (aluminum-coated steel).
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Structure grounding is specified to achieve a ground resistance of 10 ohms
or less using counterpoise buried at 2-foot depth. The "A" line uses copper-clad
counterpoise, while for the later lines galvanized steel was selected.
Counterpoise connects the anchor rods to the structure. Due to premature
corrosion of anchor rods, a passive cathodic protection system consisting of
magnesium anodes was added to all guyed towers on the "A" line. Similar cathodic
protection was included in the design of the remaining lines.
The Colstrip 500 kV Switchyard is a breaker-and-one-half arrangement with
two generator positions, two line positions, and two future positions. Each line
terminal includes a 500 kV, 100 MVA shunt reactor. An autotransformer rated
500-230 kV, 500 MVA with forced oil/forced air cooling is connected to each of
the two buses. The seven circuit breakers are ABB-ITE dead-tank, dual-pressure
SF(6) type with independent-pole operation. Connected to each autotransformer
tertiary is a reactor rated 34.5 kV, 45 MVA 3 phase. GE solid-state line
relaying is provided for each line, using microwave and power line carrier
communications. Bus and transformer protection utilizes conventional
electromechanical relays. Additional equipment includes metering, fault
recorders, fault locators, and SCADA. Two 125 volt DC batteries, each with one
charger, provide power to the control and protective systems, and a 48 volt DC
battery with charger powers communications equipment. Normal station service
power is derived from the 34.5 kV transformer tertiaries, and a 480 volt diesel
generator provides 480 volt AC power upon loss of normal station service. A
separate control building houses control and protective equipment for the
Colstrip 500 kV Switchyard.
The Broadview 500 kV Switchyard is similar to the Colstrip 500 kV
Switchyard. The breaker-and-one-half arrangement includes four line positions
and two future positions. The line terminals for lines "1" and "2" each include
a 500 kV, 100 MVA shunt reactor. An autotransformer rated 500-230 kV, 600 MVA
with forced oil/forced air cooling is connected to each of the two buses through
a motor-operated disconnect switch. The seven circuit breakers are ABB-ITE
dead-tank, dual-pressure SF(6) type with independent-pole operation. Connected
to each autotransformer tertiary is a reactor rated 34.5 kV, 96 MVA 3 phase.
Protection, metering, and battery equipment is similar to that at Colstrip.
Normal station service power is derived from the 34.5 kV transformer tertiaries,
and a 400 kW diesel generator provides 480 volt AC power upon loss of normal
station service.
The Broadview Switchyard also includes a series capacitor bank for each of
the two lines to the Colstrip Switchyard. The capacitors provide 35 percent
compensation of the line reactance, improving system stability and reducing line
losses and voltage drop. The capacitor banks are rated for 2,000 amps
continuous, 2,200 amps for one hour, and have been designed for future upgrading
to 3,000 amps continuous, 3,300 amps for one hour. The capacitor installation
includes bypass switches, protective metal oxide varistors, triggered air gaps,
and a control system with a 125 volt DC battery and chargers.
The Broadview Switchyard is equipped with an extensive security system
operated from the Colstrip Facility, with CCTV cameras, intrusion sensors, and a
fiber-optic fence disturbance alarm. Selected cameras are augmented with
infrared illumination for night viewing.
Spare parts for the 500 kV transmission lines include four tangent
structures partially assembled and ready for helicopter transport; one
unassembled deadend/angle structure; and conductor, insulators, and hardware for
one mile of line. Switchyard spares are two 500 kV circuit breaker bushings and
miscellaneous circuit breaker consumables, 500 kV switch parts, and a fiber
optic signal cable column for series capacitor platforms.
Review of Technology
The Colstrip Transmission System has been in operation at 500 kV since
about 1983. Structures on the "A" line were installed about 1970, and converted
to 500 kV about 1983.
Premature corrosion of the anchor rods on the "A" line, together with
coating degradation on the copperweld counterpoise, was addressed in the early
1980s by application of passive cathodic protection using magnesium anodes. The
anodes were designed for 25-year life, so replacement would be expected in about
the 2005 to 2010 time period. In addition, nondestructive ultrasound testing has
been conducted beginning in
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1995. About 50 percent of the structure anchors have been tested. No anchor rods
have been reported to need replacement.
Corrosion of anchor rods on the "B," "1," and "2" lines was addressed in
the design stage by use of galvanized steel counterpoise and inclusion of
magnesium anodes. Also, concrete encasement of the anchor rods was improved to
eliminate contact with soil. As with the "A" line, the anodes were sized for
25-year life and will probably need replacement in the 2005 to 2010 time period.
Structure corrosion is minimal, and in general the galvanizing appears to
be excellent. PPL Montana reports some corrosion of members east of Broadview
Substation, but it is not reported as extensive. Defective galvanizing of a
relatively small number of members is suspected.
MPC also reports that a few redundant members have broken on structures
approximately 70 to 80 miles west of Broadview. The suspected cause is
wind-induced vibration where unusual geography causes updraft winds. The broken
members have been replaced as they are found. No structure failures have been
reported, and structures elsewhere on the lines have not been reported to have
experienced this type of failure.
An infrared aerial inspection of all four transmission lines was performed
in about 1990, and no problems were reported to have been found.
MPC indicated that it considers the number of line trips to be
unacceptable, and has been researching the causes. It has concluded that
excrement from large birds which perch atop the towers is responsible for a
significant number of line trips. A pilot project is underway to provide
alternative perches and to discourage perching on the top of the towers.
The 500 kV circuit breakers have had ongoing problems with SF(6) leaks and
MPC has been replacing bushing gaskets to reduce the leakage problem.
We have reviewed the quality of equipment installed in the Colstrip
Transmission System, the general plans for operating and maintaining the
Colstrip Transmission System and the performance of the Colstrip Transmission
System. On the basis of this review, we are of the opinion that the Colstrip
Transmission System utilizes sound technology and proven methods of electric
transmission and has generally been designed and constructed in accordance with
generally accepted industry practices. Also, assuming that: (1) the system is
operated and maintained in accordance with generally accepted industry
practices, and (2) all required renewals and replacements are made on a timely
basis, we are of the opinion that the Colstrip Transmission System should have a
useful life extending well beyond the term of the Certificates.
CORETTE FACILITY
The Corette Facility is located near Billings, Montana along the
Yellowstone River. It began commercial operations in 1968 and consists of a
single boiler and STG nominally rated at 163 MW of gross generating capacity and
154 MW of net generating capacity, that can be dispatched down to 80 MW. The
unit is considered a base-loaded unit and is manually dispatched on an hourly or
as-needed basis by PPL E-Plus in Butte, Montana. The Corette Facility's capacity
is reduced during summer months due to stack plume buoyancy issues and
limitations of the electrostatic precipitator, resulting in an average annual
net electrical capacity of approximately 147 MW. The annual average net plant
heat rate is currently running approximately 11,100 Btu/kWh. The boiler had
historically fired sub-bituminous coal from the local Rosebud Mine; however, in
1996, to meet environmental regulations, the fuel supply was changed to a
low-sulfur coal from the Powder River Basin Rawhide Mine near Gillette, Wyoming.
With the closing of the Rawhide Mine in 1999, coal is currently being supplied
by other Powder River Basin mines in the same area. The unit utilizes natural
gas as a start-up fuel.
At one time, the Corette site included two generating plants: the Frank
Bird Plant and the J. E. Corette Plant. The Frank Bird Plant was dismantled in
1997, however, the turbine pedestal and plant floor remain on-site.
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The Plant Site
The Corette Facility site is located just outside the city limits of
Billings, Yellowstone County, Montana, along interstate highway Route 90 (the
"Corette Facility Site"). The site is easily accessible and provides adequate
access to the necessary utilities and rail transportation. On the basis of our
observations and historical operation of the Corette Facility, we are of the
opinion that the site is suitable for the Corette Facility's continued
operation.
The Corette Facility Site is situated on approximately 87 acres along the
Yellowstone River. The site includes the powerhouse; adjacent operating yard;
ancillary buildings and system areas; two fuel oil storage tanks, which are not
currently in service; the coal yard; and the bottom ash pond and storage area.
The Corette Facility Site is bordered on the north by Coulson Park (a city
park), on the south by MPC's Billings Division substation and the Billings
municipal waterworks, on the east by the Yellowstone River, and on the west by
Interstate Highway 90. There are two sets of railroad tracks into the site,
which run north-south through the site effectively splitting the site in half.
In addition to the railroad tracks, there is a MPC owned natural gas pipeline
that runs into the site. There is also a municipal drainage line running through
the site. Within the bottom ash processing and storage area are the terminations
of the site access roads which provide access for hauling bottom ash.
Mechanical Equipment and Systems
Pulverized Coal-Fired Boilers
The Corette Facility boiler, which was manufactured by CE, is an
outdoor-type, single-drum, tangentially-fired, natural-circulation, reheat unit
with a pressurized-furnace. The boiler includes a superheater, a reheater, an
economizer, a regenerative air preheater, superheat and reheat desuperheaters,
and a soot blowing system. The boiler was designed to operate at a maximum
continuous rating of 1,166,000 pph superheated steam flow at 1,890 psig and
1,005(DEGREES)F. The boiler is designed to burn pulverized coal as the primary
fuel and natural gas as a start-up fuel. The furnace has four burner assemblies
located at the corners of the furnace; each burner assembly has four coal nozzle
elevations, two warm-up guns, two ignitors, seven air nozzles and three
close-coupled over-fire air nozzles. The furnace was retrofitted in 1997 with
low NO(X) CE burners. In addition to start-up, natural gas is used to enhance
flame stability at low loads and for some additional load capacity. The boiler
economizer was replaced in 1989 with an improved design.
There are four coal mills, each supplies a different elevation of coal
nozzles and all four mills are needed for full-load output when burning coal.
With one mill out of service, the maximum gross generating capacity on coal is
reportedly 140 MW; however, the remaining load can be made up with supplemental
gas firing. Mill bowls were rebuilt in 1997. Primary and secondary air is
provided by two forced draft fans, located in an enclosed fan room, whose inlet
air is heated by passing through steam-coil air preheaters to maintain a
constant outlet temperature and is then heated by passing through a regenerative
air preheater. The heated air flows as primary air to the coal mills and as
secondary air to the boiler windboxes.
Steam Cycle and Heat Rejection Systems
The boiler provides steam to a single steam turbine which is a Westinghouse
two-cylinder, tandem-compound, double-exhaust, condensing reheat turbine. The
turbine and its generator are located out-of-doors with a weather enclosure. The
turbine is rated at 163,000 kW at an inlet throttle flow of 1,108,762 pph steam
at 1,800 psig and 1,000(LOGO)F/1,000(LOGO)F reheat and 3.5 inches Hg
backpressure. The STG is equipped with hydraulic control and lubricating oil
systems. A new turbine lubricating oil treatment system has been added. The
low-pressure turbine exhausts to a two-pass surface condenser where the steam is
condensed by rejecting its heat to the circulating water system.
Circulating water for the condenser is obtained through an intake structure
and intake canal located on the Yellowstone River. The intake structure consists
of two traveling water screens and two 50 percent capacity, vertical circulating
water pumps. The pumps discharge to the condenser, and after passing through the
condenser, the circulating water is discharged to the river through a discharge
structure and discharge
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canal located downstream from the intake. The retired Frank Bird plant intake
and discharge structures are still operational and are interconnected to the
Corette Facility intake and discharge pipes. There is one pump and one traveling
screen at the Frank Bird plant intake structure, which supplement flow for
certain operating conditions.
Boiler feedwater is provided by two 100 percent capacity condensate pumps
and two 65 percent capacity feedwater pumps through five feedwaters heaters. The
low-pressure feedwater heaters have admiralty tubing, while the high-pressure
feedwater heaters have been retubed with monel. The No.6 feedwater heater was
retubed with stainless steel tubes in June 2000. The feedwater cycle does not
include a deaerator. Deaeration of the feedwater occurs in a deaerating section
of the condenser. The condenser was retubed in 1982 after experiencing damage
during a chemical cleaning of the boiler.
Fuel Handling System
The on-site coal unloading system is designed to allow unloading of a
25-car train during a 12-hour shift. The 75 bottom dump railcars have a capacity
of 117 tons and are owned by PPL Montana. They were manufactured in 1994 and
1997. The railcars are unloaded into a double-outlet track hopper. Two belt
feeders feed the coal from the track hopper outlets onto a belt conveyor. The
coal is weighed by a belt scale and transferred to a radial stacker, which
discharges to the coal pile.
When coal cannot be unloaded by rail, it is obtained from an on-site
dead-storage pile, which can be reclaimed along the same coal handling feed
conveyors. Coal from the pile is moved to the reclaim area by a bulldozer. A
reclaim conveyor runs through a reclaim tunnel, located under the live storage
area of the coal pile. Four tunnel reclaim openings supply the reclaim conveyor.
The conveyor supplies coal to two conveyors on the boiler house roof which fill
the four coal bunkers. Coal flows from each of the bunkers through a feeder to
one of the four mills below.
Ash Handling Systems
Bottom ash from the boiler furnace drops to a water-filled hopper. The
refractory-lined, double-outlet ash hopper can store approximately 38 tons of
bottom ash. Pyrites collected from the pulverizers are sluiced to the bottom ash
hopper for mixing with the bottom ash and transferred to the bottom ash pond.
Two clinker grinders located at the outlet of the hoppers reduce large pieces of
ash to a size that can be transported in the ash sluicing system. Two hydraulic
jet pumps pump the ash slurry to the bottom ash settling pond located north of
the plant.
A portion of the fly ash in the flue gas stream is collected in the
boiler's economizer hoppers and is removed by a hydraulic jet pump. The balance
of the fly ash is removed by an electrostatic precipitator with eight ash
collection hoppers. Fly ash is transported from the precipitator hoppers using a
dry, pressurized air conveying system which pneumatically transports to a fly
ash storage silo. There are one 2,000-ton silo, two 1,500-ton silos, and one
300-ton silo at the Corette Facility Site.
Make-Up Water System
Boiler makeup water is generated from the city potable water supply
utilizing water softeners and a new water treatment system consisting of a
reverse osmosis unit and electronic demineralizer that has been in service since
September 1999.
Additional Structures and Systems
The Corette Facility has two new 100 percent capacity oil free rotary screw
air compressors. Both service air and instrument air are supplied from the same
compressed air header.
City water is distributed for various services within and outside of the
power building, including fire protection. Should header pressure drop too low a
natural gas engine-driven firepump starts automatically taking suction from the
city water line and discharging to the plant header.
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Since the boiler began burning Powder River Basin coal in 1996, four mill
combustion incidents have been reported due to the nature of the Powder River
Basin coal. Reduction of the mill outlet temperature reportedly has been
adequate to prevent further mill incidents. Fire suppression systems were added
to the feeders and mills, and new isolation dampers are to be installed on the
feeders in 2000.
The Corette Facility contains a number of buildings and significant
structures, including: the turbine enclosure and administration building; the
coalyard stock-out conveyor building; the precipitator building; the warehouse;
the circulating water intake structure; the flyash silo and unloading station
building; the ash pond chemical treatment building; coal unloader building; a
100,000 gallon condensate storage tank; and an activity center building, as well
as a number of transmission towers.
The Corette Facility has a 350-foot, reinforced-concrete, steel lined
chimney with a diameter of 11.5 feet. Testing enclosures at the 175-foot
elevation house the CEMS and stack testing ports.
Electrical and Control Systems
The steam turbine drives a Westinghouse generator rated 202 MVA at 0.85
power factor, 18 kV. The original shaft-driven brushless exciter system has been
modified by removal of the rotating pilot exciter and substitution of a static
pilot exciter system provided by ABB. The generator suffered a failure in 1997
when a generic problem with cooling fan blades caused damage to both rotor and
stator. The repair included replacement of the rotor with a new Westinghouse
rotor and a complete rewind of the stator.
The generator is connected through isolated phase bus duct to the main
generator step-up transformer, an ABB outdoor oil-filled unit rated 18-100 kV,
192 MVA with forced oil/forced air cooling. The original main generator step-up
transformer, a Westinghouse outdoor oil-filled unit rated 17.2-100 kV, 171.5
MVA, was replaced in 1991 after its condition was determined to be questionable.
It is currently available on-site as a spare.
The generation point of receipt is the bus side of the generator circuit
breaker (designated 100-98) in the Billings Steam Plant Switchyard. Metering has
been provided at this point by PPL Montana.
Auxiliary power is derived from the generator circuit with start-up power
derived from the adjacent 50 kV switchyard. The auxiliary transformer is an
outdoor, oil-filled unit manufactured by Pennsylvania Transformer and rewound by
U.S. Transformers in 1992. It is rated 17.2-4.16 kV, 14 MVA.
Auxiliary start-up power is supplied from the 50 kV switchyard through a
50 - 4.16 kV outdoor oil-filled transformer manufactured by Pennsylvania
Transformer and rewound by U.S. Transformer in 1992. This transformer is also
rated 14 MVA. A used spare auxiliary start-up transformer is on-site. In
addition, an outdoor oil-filled 12.47 kV - 480 V, 1500 kVA transformer provides
power from the local MPC distribution system for essential power when the plant
is shut down.
The start-up power point of interconnection is the 50 kV bus tap on the
high side of the start-up transformer. Metering has been provided at this point
by PPL Montana. The interconnection point for the essential power circuit is the
12.47 kV transformer bushings.
Medium voltage switchgear is the air-magnetic type manufactured by ITE.
Three 4.16 kV-480 volt outdoor oil-filled transformers, two rated 1500 kVA and
one rated 500 kVA, provide low voltage power for smaller motors and
miscellaneous plant loads, and lighting transformers are connected to the 480
volt systems for lighting and general power requirements.
Motor Control Centers ("MCCs") are obsolete, but the most critical unit is
being replaced in 2001 with current production equipment. Components from
replaced equipment will be available as spares for remaining original equipment
MCCs.
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AC and DC Critical Systems
A single 125 volt DC battery system, equipped with a 50 amp charger,
supplies critical DC loads including protection systems. A UPS with a separate
125 volt DC battery is used to power the DCS. A 48 volt DC system provides
communications power.
In addition, a 300 kVA, 480 volt, AC diesel generator can supply critical
AC loads including turning gear if all external power is lost for an extended
period. The diesel is started by compressed air provided by a
gasoline-engine-driven compressor. The Corette Facility does not have black
start capability.
The plant communications system is a typical Gai-Tronics page-party public
address/telephone system. Radios are used to supplement the Gai-Tronics system.
Plant Control System
The control room was completely redone in the summer of 1998 and a
Honeywell DCS installed. In conjunction with this installation, new burner
management and flame scanner safety systems were provided. The turbine control
system is the original hydraulic system, with interface to the DCS. Automatic
load dispatching capability is provided with the existing controls.
Environmental Controls and Equipment
Air Emissions
The Corette Facility's Title V Air Operating Permit contains air emission
limits for the key pollutants of particulate matter, SO(2), NO(X) and opacity.
The basic air pollution control technologies employed at the plant to control
the aforementioned pollutants are an electrostatic precipitator for the control
of particulates and opacity, and Low-NO(X) burners for the control of NO(X)
emissions. The emissions of SO(2) are controlled by the sulfur content of the
coal burned at the plant.
The precipitator, which was manufactured by Research-Cottrell, consists of
four electrical sections, each containing 39 parallel ducts with stainless steel
discharge electrodes, collecting plates, and magnetic rappers. Each section is
provided with a transformer-rectifier set, a saturation reactor, and a rectifier
control unit. The collecting plates, which are 30 feet high by 9 feet wide, are
cleaned with magnetic impulse rappers. The precipitator is designed for 600,000
actual cubic feet per minute ("acfm") at 96 percent collection efficiency, and
the inlet duct contains three perforated distribution plates to provide uniform
gas distribution. The precipitator is enclosed in a steel shell and equipped
with eight ash collection hoppers (four per row, two rows). A steel-top housing
covers the roof of the precipitator to enclose and protect the high voltage
insulators, high voltage connections and rapper shafts. In 1988, the
precipitator controls were replaced with new Westinghouse controls.
The inlet temperature of the electrostatic precipitator must be kept below
280(DEGREES)F. Operation at higher temperatures adversely affects the
resistivity of the fly ash, therefore, decreasing the particulate removal
efficiency in the precipitator. In order to maintain the precipitator
temperature below 280(DEGREES)F, a certain amount of combustion air is bypassed
(after the air heater) from the input to the boiler to a point upstream of the
precipitator, thus lowering the exit temperature from the boiler. The by-pass
reduces the efficiency and output of the boiler.
The low-NO(X) burners installed during 1997 are used for the control of
NO(X) emissions. The boiler is not equipped with separated overfire air due to
the fact that insufficient room exists at the top of the furnace for such
installation. The unit achieves NO(X) emission rates in the 0.25 to 0.40
lb/MMBtu range on a routine basis. Such rates are in compliance with the limits
set forth in the Operating Permit and in compliance with the NO(X) limits set
forth in the Tile IV Acid Rain Permit.
The Corette Facility is equipped with CEMS which include SO(2), NO(X),
opacity, CO(2) and flow monitoring systems. The SO(2), NO(X), CO(2), flow and
opacity monitors are of the in-situ type. The CEMS were upgraded including the
data acquisition system and flow monitors to meet the 40 CFR Part 75 monitoring
regulations.
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Wastewater/Solid Waste Disposal
Bottom ash from the Corette Facility is sluiced to a bottom ash pond area
consisting of two ponds. The ash is allowed to settle and the sluice water flows
from Pond 1 to Pond 2 before discharging to the Yellowstone River via a
permitted outfall. Low volume wastewaters such as boiler blowdown, floor drains,
softener backwash, and equipment floor drains are also routed to the bottom ash
pond for treatment before discharge to the Yellowstone River. Sulfuric acid is
added at the inlet of Pond 2 for pH control. The floor drains wastewater flows
through an oil/water separator prior to disposal in the bottom ash ponds.
The fly ash at the Corette Facility is collected dry and stored in silos
before removal from the site. The fly ash along with excavated bottom ash from
the bottom ash pond is sold, therefore, minimizing the need for disposal areas
on-site.
Off-Site Requirements
Potable water, makeup water and water for fire protection is taken from a
City of Billings 24-inch diameter water pipeline. The Yellowstone River is the
source of water supply to the City of Billings.
The station output is interconnected to the MPC grid at 100 kV in the
Billings Steam Plant Switchyard. Startup power is obtained from the MPC grid at
50 kV. The 100 kV bus is connected to 230 kV and 50 kV portions of the
switchyard through autotransformers. There are four 230 kV transmission circuits
and five 100 kV transmission circuits. The 50 kV portion is used for local
distribution.
Coal is delivered to the Corette Facility Site by railroad in 25 car
increments by a Montana rail link after being transported by Burlington Northern
from the mine. Fly ash and bottom ash are sold and removed from the site.
Cooling water for the Corette Facility is taken from and returned to the
Yellowstone River. Wastewater is treated and discharged to the river. Natural
gas is received from an MPC pipeline which runs on-site. Sewerage is discharged
to a municipal sewer line running through the site.
Review of Technology
Additional information regarding the technology incorporated in the Corette
Facility is included in the Review of Technology section for the Colstrip
Facility since both plants employ the same technology with the exception of flue
gas cleanup. The Corette Facility does not have a flue gas sulfur dioxide
removal system. It does employ an electrostatic precipitator to remove
particulates (fly ash) from the flue gas stream. The electrostatic precipitator
in use at the Corette Facility is typical of the type of design employed on
numerous pulverized coal fired power plants thirty years ago.
In general, the Corette Facility has been normally base loaded with the
exception of the spring time when river water conditions yield excess hydro
generation or during the summer months when output is limited to approximately
147 MW due to stack plume buoyancy issues and limitations of the electrostatic
precipitator. Based on discussions with PPL Montana operating and maintenance
personnel and review of operating reports for the past five years it appears
that the boiler is subject to slagging and that tubes have experienced failures
due to water side damage caused by hydrogen embrittlement, thus presenting the
potential for a severe incident. Portions of the boiler's west waterwalls found
to have corrosion problems were replaced in 1999. Reportedly, problems with the
plants' boiler water monitoring practices have made it difficult to determine
the cause of the failures. A water chemistry contractor has been retained to
monitor the boiler water chemistry and train PPL Montana employees. The new
water treatment system should also help reduce corrosion problems as should the
new water sampling system to be installed in June 2000.
Performance in 1997 was adversely affected by a 12-week scheduled outage in
the summer of 1997 in which the control room was redone and a distributed
control system was installed. It was further impacted by a forced outage in late
1997 due to the electric generator failure which required the replacement of the
rotor and a complete rewind of the stator. The outage extended into 1998
adversely impacting that year's performance as well. Other than some continuing
pluggage problems in the boiler backpass and air heaters, there were no major
issues that affected the performance of the unit in 1999.
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Based on our review, we are of the opinion that the Corette Facility has
been designed and constructed in accordance with good engineering practices and
generally accepted industry practices and the technology in use at the Corette
Facility is a sound, proven, conventional method of electric and thermal
generation. Furthermore, all major off-site requirements of the Corette Facility
are adequately provided for, including coal supply, water supply, and electrical
interconnections. If operated and maintained as they are currently, the Corette
Facility should be capable of meeting the currently applicable environmental
permit requirements.
Availability
Based on historical performance data from the Corette Facility, review of
operations and maintenance practices and procedures and general observation of
the Corette Facility, we are of the opinion that it should be capable of
achieving a projected annual average equivalent availability factor of 85.7
percent over the term of the Certificates. There will be years when the
availability factor is both above and below the projected annual average.
Estimated Useful Life
We have reviewed the quality of equipment installed at the Corette
Facility, the general plans for operating and maintaining the facility and the
performance of the Corette Facility to date. On the basis of this review and
assuming that: (1) the plant is operated and maintained in accordance with the
policies and procedures as presented by PPL Montana, (2) all required renewals
and replacements are made on a timely basis as the unit ages, and (3) coal and
natural gas burned by the plant are within the expected range with respect to
quantity and quality, we are of the opinion that the Corette Facility should
have a useful life extending well beyond the term of the Certificates.
HYDROELECTRIC FACILITIES
The Hydroelectric Facilities include eleven generating plants and one
storage reservoir without generation licensed by FERC as four projects. The
storage reservoir together with eight of the generating plants are licensed
together as the Missouri-Madison Plants, FERC Project No. 2188. Each of the
other three generating plants is licensed by FERC as a separate plant. On the
basis of our observations and historical operation of the Hydroelectric
Facilities, we are of the opinion that the sites are suitable for the
Hydroelectric Facilities' continued operation. The Hydroelectric Facilities are
described in the following paragraphs.
Missouri-Madison Plants
The Missouri-Madison Plants includes nine facilities located on the Madison
and Missouri Rivers. Two of the facilities, Hebgen Reservoir and the Madison
Plant, are located on the Madison River. The other seven plants are located on
the mainstem of the Missouri River.
The Hebgen Reservoir is located near the southern border of Montana on the
Madison River. Hebgen Reservoir is formed by Hebgen Dam, a 721-foot long,
81-foot high earthfill gravity dam with a concrete core wall. The dam was
completed in 1915. The spillway is a 375-foot long side channel with a capacity
of 7,000 cfs. Normal releases are made through a concrete intake structure on
the left side of the reservoir, a 785-foot long, 12-foot diameter concrete pipe
that conducts the releases back to the Madison River downstream of the dam. The
Hebgen Reservoir is used both as a storage facility to regulate flows for power
production and also for flood control in the Madison River. Releases are
controlled to maintain minimum flows downstream, also the operators attempt to
limit flows in the Madison River at Kirby Ranch to less than 3,500 cfs to
prevent erosion of the river banks. They also try to limit changes in outflow to
no more than 10 percent per day from August 1 through March 31.
The Madison Plant is located on the Madison River about 60 miles downstream
of the Hebgen Reservoir. It was constructed in 1906 and includes a 257-foot
long, 38.5-foot high dam, a 140-foot long spillway, intake, 7,500-foot long
13-foot diameter steel pipe flowline, concrete surge chamber, four 9-foot
diameter penstocks, and a masonry powerhouse. The powerhouse contains four
horizontal shaft Francis turbines connected to 2.25
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MW electric generators. The planned replacement of the existing
electro-mechanical equipment in 2004 together with tailrace improvements in 2004
will increase total capacity of the plant to 10.3 MW.
The Hauser Plant is located on the Missouri River about 14 miles northeast
of Helena, MT and downstream of the Bureau of Reclamation's Canyon Ferry
Project. The Hauser Plant was completed in 1911 and includes a 700-foot long,
80-foot high concrete gravity dam with a controlled ogee crest spillway, an
intake and forebay at the right abutment, steel penstocks, and a masonry
powerhouse. The powerhouse contains six horizontal Francis turbines connected to
electric generators with a total capacity of 17 MW. There are also three
hydraulic exciters. Upgrading of the electrical and mechanical equipment is
planned between 2000 and 2005 which will increase the total generating capacity
by 4.5 MW.
The Holter Plant is located on the Missouri River about 25 miles downstream
of the Hauser Plant. It was completed in 1918 and the plant facilities include a
1,364-foot long, 124-foot high concrete gravity dam with a 682-foot long
controlled overflow spillway section, an intake section at the left abutment
with steel penstocks leading to a powerhouse integral with the intake. The
powerhouse is a 208-foot long concrete and steel structure housing four vertical
Francis turbines and electric generators with a total capacity of 50 MW. The
generators were all rewound in the 1960's and no major expansions are planned
for the Holter Plant. The powerhouse also contains a switchyard that will remain
with MPC.
The remaining five plants of the Missouri-Madison Plants are located in a
13-mile reach of the Missouri River at Great Falls, Montana. In descending order
from upstream to downstream they are the Black Eagle, Rainbow, Cochrane, Ryan,
and Morony Plants.
The Black Eagle Plant first went on line in 1891, and was completely
rebuilt in 1927. It includes a 782-foot long, 34.5-foot high concrete gravity
dam with a controlled ogee crest spillway section 646 feet long, a 421 foot by
96 foot forebay that forms the left abutment of the dam, and an integral intake
and powerhouse. The powerhouse contains three vertical Kaplan turbines and
electric generators with a total capacity of 18 MW. All three generators were
rewound between 1978 and 1982. During the site visit MPC staff were installing
automation controls that will allow remote operation of the Black Eagle Plant
from the main control room at the Rainbow Plant. There are no plans for capacity
additions at the Black Eagle Plant.
The Rainbow Plant was completed in 1910. It includes a 1,146-foot long,
43.5-foot high rockfill timber crib and concrete gravity dam with an integral
overflow spillway, two intake structures leading to steel flowlines, surge tank
and chamber, penstocks to the powerhouse, and a brick masonry powerhouse. The
powerhouse contains eight horizontal Francis turbines with a total capacity of
35 MW. The Rainbow Plant is not automated and must be manually controlled. The
Rainbow Plant's license application filed by MPC includes provisions allowing
for construction of a new powerhouse increasing the total capacity to 58 MW.
Based on an economic review of the plant redevelopment, PPL Montana may decide
not to construct a new powerhouse but to renovate the existing one with new
units that will add 6.6 MW in 2009 for a total capacity of 41.6 MW.
The Cochrane Plant was completed in 1958 and includes a 856-foot long,
100-foot high concrete gravity dam with a 334-foot long overflow spillway
section controlled by radial gates, an integral intake and powerhouse section
188 feet long. The powerhouse is 130 feet by 65 feet reinforced concrete
structure housing two vertical Kaplan turbines and electric generators with a
total capacity of 54 MW. Redevelopment of the Rainbow Plant with a new
powerhouse would allow the Cochrane pool to operate about 6 feet higher than at
present and would increase the capacity of the Cochrane Plant by about 5 MW.
Redevelopment of the Rainbow Plant at the existing powerhouse would not allow
the higher pool, hence the capacity of the Cochrane Plant will remain 54 MW.
The Ryan Plant was completed in 1915 and it consists of a 1,465-foot long,
82-foot high concrete gravity dam with an overflow spillway, and intake to six
steel penstocks leading to a brick masonry powerhouse. The powerhouse contains
six vertical Francis turbines and electric generators with a total capacity of
60 MW. An upgrade of the Ryan Plant is proposed for 2001 and 2002 that will add
12 MW of capacity. The powerhouse contains a switchyard that will remain with
MPC.
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The Morony Plant was completed in 1929 and consists of an 842-foot long,
96-foot high concrete gravity dam with a 390-foot wide spillway controlled with
9 radial gates and one slide gate, an intake and powerhouse at the left end of
the spillway. The powerhouse is a semi-outdoor type containing two vertical
Francis turbines and electric generators with a total capacity of 48 MW. No
major expansions are planned for the Morony Plant.
Thompson Falls Plant
The Thompson Falls Plant is licensed by the FERC as Project No. 1869 and is
located on the Clark Fork River in western Montana at the town of Thompson
Falls. The license was issued in 1979 and terminates December 31, 2025. The
license was amended in 1990 to allow for the construction of Unit 7.
The Thompson Falls Plant consists of two dams, (the main dam and the Dry
Channel Dam) the original intake and powerhouse, and the Unit 7 powerhouse and
intake. The main dam is a 913-foot long concrete gravity structure with two 41
ft by 18 ft radial gates and 38 bays with removable panels, flashboards, and
stanchions. The Dry Channel Dam has two sections: a non-overflow sluiceway
section 122 feet long and 38 feet high, and an overflow ogee section 289 feet
long which has 12 bays with removable panels, flashboards, and stanchions. The
original powerhouse is a steel and concrete structure with a cut rock exterior,
and the intake is integral with the powerhouse. It contains six vertical Kaplan
turbines and electric generators with a total capacity of 36 MW. The original
plant was constructed in 1915. Unit 7 was completed in 1995 and is a reinforced
concrete structure containing one 50 MW vertical Kaplan turbine and electric
generator. Unit 7 is located between the original powerhouse and the Dry Channel
Dam. The powerhouse also contains a switchyard that will remain with MPC.
Kerr Plant
The Kerr Plant is located at the south end of Flathead Lake on the Flathead
River. It is licensed by the FERC as Project No. 5 and is a joint license to PPL
Montana and the Confederated Salish and Kootenai Tribes ("CSKT"). Under the
terms of the license, PPL Montana will own and operate the Kerr Plant until
2015. Anytime during the next ten years (2015 to 2025), the CSKT may, at their
discretion and with at least one year's written notice, take over ownership of
the Kerr Plant and continue operation through 2035, the end of the current
license. If CSKT decides to take over ownership of the Kerr Plant, they will pay
PPL Montana an amount according to a formula specified in the FERC license equal
to original cost less depreciation.
The Kerr Plant was originally constructed in 1939 and consists of a
concrete arch dam with 14 overflow spillway gates across the crest, a concrete
intake on the left abutment of the dam, three concrete and steel lined penstock
tunnels, and a concrete powerhouse containing three vertical Francis turbines
and electric generators with a total installed capacity of 189 MW.
Mystic Plant
The Mystic Plant is located at the headwaters of West Rosebud Creek in
south central Montana. It is licensed by FERC as Project No. 2301. The license
was issued in 1976 and ends December 31, 2009.
The Mystic Plant was originally constructed in 1927 and consists of a
concrete arch dam 368 feet long and 45 feet high, a concrete intake, a
10,000-foot long flowline, a 118.5-foot high surge tank, a steel penstock 2,566
feet long between the surge tank and powerhouse, and a reinforced concrete
powerhouse with two horizontal Pelton turbines and electric generators with a
total installed capacity of 11 MW. In 1978 a reregulating dam was constructed
downstream of the powerhouse.
Review of Technology
Hydroelectric power is a conventional form of electricity generation with a
proven track record for nearly 100 years. Hydroelectric power plants contain
equipment that convert hydraulic energy into electric energy. Water under
pressure is released in a controlled manner through waterways, called penstocks,
to drive waterwheels, or turbines. The turbines are connected to generators
which rotate to produce electricity through
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magnetic coils. The "de-energized" water is discharged from the turbines into a
tailrace channel which returns the water to the river. Hydroelectric projects
can make use of natural features such as waterfalls or cascades or man made dams
to develop the head required to create the pressure in the water. Dams can also
create reservoirs that allow for storage of water during wet periods and
subsequent release of water during dry periods.
Based on the information provided and our site visits, the Hydroelectric
Facilities appear to be in generally good condition. We were able to visit all
the plants except the Mystic Plant which was inaccessible due to the time of
year and the weather. The plants were well maintained and cared for, with all,
except the recently completed Unit 7 at Thompson Falls, having been in service
for many years. The civil works appeared to be in adequate to good condition.
The condition of the electrical and mechanical equipment varied according to the
age of the plant and any improvements that had been made. The plants are
regularly inspected, both by PPL Montana staff and by independent consultants.
Based on the observations during the site visits and discussions with the staff
at the plants, problems identified during the inspections are corrected, and
recommendations for improvements are carefully considered.
Voith Hydro Co. inspected the electro-mechanical equipment at the Madison,
Hauser, Holter, Rainbow, Ryan, and Thompson Falls Plants and prepared reports
with recommendations for replacements and upgrades of the units. MPC used these
reports together with in-house inspections and analysis to develop a 15-Year
Capital Requirements Program for the Hydroelectric Facilities from 1998 through
2012. This 15-year program includes capacity upgrades, replacement of units, and
plant and unit refurbishments. MPC started work on the capital program and PPL
Montana is continuing it.
FERC requires that the owners of licensed hydroelectric plants have their
dams inspected by a qualified independent consultant every five years. The
independent dam safety inspections include a physical inspection of the plants
and its facilities, an analysis of the spillway adequacy for the Probable
Maximum Flood ("PMF"), and an analysis of the stability of the dam and other
critical structures under various possible loading conditions. MPC had the
Hydroelectric Facilities inspected by Raytheon Infrastructure Services Inc.
(formally Ebasco) on a regular basis as required by the FERC.
Table 2 lists the dates of these reports and the general findings regarding
each plant. The Overall Condition column lists the general assessment included
in each report of the dam and safety related equipment. The Spillway Adequacy
column lists whether or not the spillway can pass the PMF. None of the reports
contained recommendations for adding to the spillway capacity, even if there
were potential for overtopping the dam. Since most of the dams are concrete
structures on rock, overtopping during the PMF is a concern only if it causes
structural instability. The stability column lists the results of the stability
analysis and the conclusions regarding the stability of the dams and related
structures.
TABLE 2
FERC DAM SAFETY INSPECTION REPORTS
OVERALL
PLANT REPORT DATE CONDITION SPILLWAY ADEQUACY STABILITY
- ----- -------------- --------- -------------------- -------------------
Thompson Falls....... October 1996 Good Overtops by 1.9 ft See below
Kerr................. October 1996 Good Adequate Adequate
Mystic............... October 1998 Good Overtops Adequate
Hebgen Reservoir..... September 1994 See below Adequate Adequate, see below
Madison.............. October 1999 Good Overtops by 12.1 ft Adequate
Hauser............... October 1995 Good Overtops by 6.8 ft Adequate
Holter............... October 1995 Good Overtops by 3.4 ft Adequate
Black Eagle.......... October 1995 Good Adequate Adequate
Rainbow.............. October 1998 Good Overtops by 5.3 ft See Below
Ryan................. October 1999 Good Adequate Adequate
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OVERALL
PLANT REPORT DATE CONDITION SPILLWAY ADEQUACY STABILITY
- ----- -------------- --------- -------------------- -------------------
Cochrane............. November 1998 Good Overtops by 13 ft See Below
Morony............... October 1999 Good Overtops by 4.8 ft Adequate
As shown in Table 2, the independent dam safety inspections found that the
dams and water control structures at the hydro plants were generally in good
condition with an adequate stability. The dam safety inspections do not cover
the powerhouse or generating equipment. In some cases the inspection found
conditions that needed repair or correction. These cases are discussed in the
following paragraphs.
The dam stability analysis of the Thompson Falls dams found that some
sections of the main dam could fail under a normal pool plus ice loading case.
In order to avoid problems with ice loading on the dam, MPC monitored the ice
formation at the dam and removes ice when necessary. Since completion of Unit 7,
the flow pattern at the dam has been such that ice buildup has not been problem.
The stability analysis of the Dry Channel Dam indicated that it would be
unstable under the full PMF, but that it is stable under a flood that is 90
percent of the PMF. Since the Thompson Falls dams are classified as low hazard,
this is considered adequate.
During the dam safety inspection of the Hebgen Reservoir dam, it was noted
that spalling and concrete erosion on the spillway wingwalls were due to alkali
aggregate reaction. Since the inspection, MPC repaired the concrete surfaces and
PPL Montana is monitoring the walls for signs of additional erosion. Earthquake
analyses of the embankment dam indicated that some shallow surface sloughing of
the upstream face could occur, but that they would not compromise the water
retaining integrity of the dam due to the concrete core wall. A seismic upgrade
of the intake tower is planned in the summer of 2001. Remediation work will
include mass concrete in the intake structure plus eight vertical post-tensioned
anchors to stabilize the mass concrete during seismic loading conditions.
The Rainbow dam safety report identified some sections of the dam and surge
structure with factors of safety less than one under certain extreme loading
conditions. The report also included recommendations that these be accepted
because the conditions are unlikely to occur, and, even if a failure were to
occur, it would not threaten life or other property. According to PPL Montana
staff, FERC has accepted these recommendations.
The Cochrane dam stability analysis showed that some of the dam sections
have a factor of safety of less than one under the PMF loading. MPC engineers
thought that additional foundation investigations would justify changes to the
coefficient of friction between the dam and the foundation rock such that the
factor of safety would increase to above one. However, the investigations
required are quite costly, and MPC did not think they were justified. MPC asked
FERC for a waiver on this matter. FERC has not yet responded to the request.
Based upon our review of the dam safety inspection reports for the
Hydroelectric Facilities conducted for PPL Montana, we are of the opinion that
the dam safety inspection reports for the Hydroelectric Facilities were
conducted in a manner consistent with industry standards, using comparable
industry protocols for similar studies with which we are familiar.
Based on our review, we are of the opinion that the Hydroelectric
Facilities have been designed and constructed in accordance with good
engineering practices and generally accepted industry practices, and the
technology in use at the Hydroelectric Facilities is a sound, proven,
conventional method of electric generation.
Estimated Useful Life
We have reviewed the quality of equipment installed, the general plans for
operating and maintaining, and the performance of the Hydroelectric Facilities.
On the basis of this review and assuming that: (1) the Hydroelectric Facilities
continue to be operated and maintained in accordance with the established
policies and procedures, and (2) all required renewals and replacements are made
on a timely basis, we are of the
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opinion that the Hydroelectric Facilities should have a useful life extending
well beyond the term of the Certificates.
ENVIRONMENTAL ASSESSMENTS
ENVIRONMENTAL SITE ASSESSMENTS
MPC prepared a Phase I environmental site assessment for each of the
Colstrip and Corette Facilities and the Hydroelectric Facilities (including the
Hebgen Reservoir) dated May 1998. The Phase I environmental site assessments
consisted of site reconnaissance, interviews, review of facility files, and
review of relevant government agency files. MPC subsequently retained a
consultant who has experience in environmental site assessments to perform Phase
II environmental investigations at Colstrip and Corette Facilities and several
of the Hydroelectric Facilities in August 1998. The environmental site
consultant provided an update to its estimates in October 1999 and PPL Montana
revised these estimates in May 2000. The Phase II investigations consisted of
(1) site reconnaissance of the facilities, (2) supplemental interviews with MPC
and regulatory personnel, (3) additional research and data review regarding
various issues, and (4) sampling of soil and groundwater at various portions of
the sites for the Plants.
Based upon our review of the environmental site assessments conducted by
MPC and the additional review and subsurface investigations conducted for PPL
Montana for the Colstrip and Corette Facility sites and the Hydroelectric
Facility sites, we are of the opinion that the environmental site assessments
and subsurface investigations of the sites for the Plants were conducted in a
manner consistent with industry standards, using comparable industry protocols
for similar studies with which we are familiar.
Under terms of the Asset Purchase Agreement, MPC has agreed to indemnify
PPL Montana for certain pre-existing environmental remediation claims identified
in the Phase II environmental site assessment with respect to the Montana
Portfolio. PPL Montana is also indemnified for pre-closing unknown liabilities
for a period of two years after closing, which occurred on December 17, 1999.
The Asset Purchase Agreement provides that MPC's liability is limited to: (1) 50
percent of the covered remedial costs at the Hydroelectric Facilities, the
Hebgen Reservoir, and the Corette Facility; and (2) 50 percent of PPL Montana's
pro-rata share of the covered remedial costs at the Colstrip Facility. MPC is
not required to indemnify PPL Montana for losses attributable to acts or
omissions of PPL Montana resulting in an increase in or aggravation of such
environmental liabilities.
COLSTRIP FACILITY
For the Colstrip Facility, MPC's Phase I environmental site assessment
consisted of a site reconnaissance, review of plant files, and interviews with
plant personnel and Montana Department of Environmental Quality ("MDEQ")
representatives. According to MPC, the Colstrip Facility Site was mostly
undeveloped prior to initial construction in 1972. Portions of the site had been
previously been mined for coal or historically used as the County landfill
(currently closed). The Phase I environmental site assessment identified a
complex system of ponds used for the discharge of plant effluents and coal ash.
According to MPC, leaks from the ponds have resulted in impacts to groundwater
over various portions of the Colstrip Facility Site. MPC installed groundwater
capture systems to mitigate the environmental impacts. Several areas were
identified where additional investigations and groundwater capture systems will
be required to maintain compliance with its Certificate of Environmental
Compatibility and Public Need. In addition, MPC identified other historically
significant spills primarily consisting of releases of petroleum products and
other miscellaneous areas of concern. Additional interviews were conducted on
behalf of PPL Montana with MDEQ and plant personnel and Colstrip Facility files
were reviewed in order to supplement the Phase I investigations by MPC and to
prepare cost estimates for areas of concern identified by MPC and/or
independently identified in the environmental site assessment. Phase II
investigations consisted of limited soil sampling, collection of numerous
groundwater samples from existing wells and selective analysis for organic and
inorganic constituents. Based on these studies, estimates were prepared by PPL
Montana in May 2000, which included mitigation of the issues identified above.
According to PPL Montana, its share of the "Most Probable" case
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scenario for mitigation of the above issues is now estimated to be approximately
$3,800,000 in 2000 dollars for capital expenditures and operation and
maintenance spread over the period between 2000 to 2020. Most of these costs
were attributable to issues associated with groundwater impacted by the Colstrip
Facility's system of effluent/ash disposal ponds. These pond-associated costs
would cover additional groundwater investigations, pond closures/construction,
dam repair, installation of groundwater capture systems, and long-term
groundwater monitoring projects. The remaining areas of mitigation included
issues associated with coal pile leachate management, excavation and disposal of
lead-contaminated soil at an on-site shooting range, and various other petroleum
products spills and potential groundwater contamination issues. PPL Montana
included an item from the "Low Probability" case scenario that a synthetic liner
would be required for a portion of the Colstrip Units 3 and 4 effluent holding
pond, in the event that planned groundwater capture mitigation measures were
ineffective. Should a liner installation be required, PPL Montana estimated its
share of the cost to be $2,000,000 in 2000 dollars, spread between 2010 to 2014.
During the 1999 Phase I inspection of the Colstrip Units 3 and 4 effluent
pond, main, and saddle dams, settlement cracks were observed in the saddle dam
in addition to the seepage being observed downstream of the dam. It was
recommended that additional investigations be conducted to define the extent and
cause of both problems. PPL Montana has contracted for both studies to proceed.
The consultant conducting the investigations has recommended that grouting of
the foundation be done to seal seams of rock that are allowing the seepage to
occur. The consultant is continuing to investigate the settlement cracks and
will have a final report to MDEQ by the end of July 2000. PPL Montana's share of
the costs for repair of the settlement cracks could range from $75,000
associated with continued monitoring to $2,250,000 if replacement of the entire
saddle dam was required. The consultant has stated that preliminary results
indicate that the settlement cracks are due to settlement in the foundation and
not to an instability of the dam. Therefore, the repair would not require
replacement of the dam.
Corette Facility
For the Corette Facility, MPC's Phase I environmental site assessment
consisted of a site reconnaissance, review of plant files, and interviews with
plant personnel and MDEQ representatives. According to MPC, the site was
undeveloped farmland prior to initial development of the site in 1950, which
consisted of construction of the Frank Bird plant, which was shut down in 1984,
and dismantled in 1997. The Corette Facility became operational in 1968. The
Phase I environmental site assessment identified minor historical
spills/releases of oil and other potentially contaminated areas resulting from
historical power plant operations.
Additional interviews were conducted on behalf of PPL Montana with MDEQ and
Corette Facility personnel and plant files were reviewed in order to supplement
the Phase I investigations by MPC and to prepare cost estimates for areas of
concern identified by MPC and/or independently identified by the environmental
site consultant. Phase II investigations consisted of limited soil sampling,
collection of groundwater samples and selective analysis for organic and
inorganic constituents. Cost estimates were prepared to address certain issues
including mitigation of a former on-site flyash landfill, management of coal
pile leachate, and additional investigations regarding the presence of
tetrachlorethene (PCE, a chlorinated industrial solvent) found in the
groundwater during sampling investigations. According to PPL Montana, its share
of the "Most Probable" case scenario cost for mitigation of the above issues is
estimated to be approximately $700,000 in 2000 dollars for capital expenditures
and operation and maintenance spread over the period between 2000 to 2020.
Hydroelectric Facilities
For the Hydroelectric Facilities, MPC prepared Phase I environmental site
assessments for each of the eleven hydroelectric plants and the Hebgen Storage
Reservoir. The Phase I environmental site assessment reports, dated May 1998,
consisted of site reconnaissance, interviews, review of facility files, and
review of relevant government agency files. Phase II environmental
investigations were performed at several of the Hydroelectric Facilities. The
Phase II investigations consisted of (1) site reconnaissance to the facilities,
(2) supplemental interviews with MPC and regulatory personnel, (3) additional
research and data review regarding various issues, and (4) sampling of soil and
groundwater at various portions of the plant sites. Cost
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estimates were prepared by PPL Montana in May 2000 which address several issues
either raised within the Phase I environmental site assessments or by the
supplemental investigations conducted by the environmental site consultant.
Except for the Kerr and Cochrane plants, initial construction of the dams
and power plants occurred before 1930. Some of the plants have been upgraded
since their original construction. The investigations encountered no evidence of
buildings or industrial activities prior to construction of the Hydroelectric
Facilities. In addition to the facilities directly related to hydroelectric
power generation, some of the sites had former "employee camps" associated with
residential activity and recreational facilities. The following issues were
common at several of the Hydroelectric Facility sites:
- Use of various chemicals and hazardous substances and generation of used
oil and small amounts of hazardous waste were recognized by the
investigations.
- Former or current use of underground storage tanks ("USTs") were
identified at several sites. Only one site had currently active USTs.
- Spills of petroleum products or other release incidents. According to the
environmental site consultant, none of these incidents resulted in
citations or involve any ongoing assessment, remediation, or unresolved
regulatory issues.
- Potential for PCB-containing equipment and potential spill/leak issues.
- Septic systems and leachfields.
- Former household trash disposal areas.
- Known or suspected asbestos-containing materials exist at the plants
within floor tiles, ceiling tiles, transite materials, brake shoes, and
insulation. It was noted that remodeling projects consider the potential
for asbestos prior to demolition or project activities.
- Lead-based paint was identified as likely to exist at the facilities.
- The potential for elevated metals in reservoir sediments.
The environmental site consultant's review of the above potential concerns
identified certain issues that potentially require mitigation at some of the
Hydroelectric Facility sites. According to the combined estimates provided by
PPL Montana, its share of the "Most Probable" case scenario total cost estimate
associated with former household trash dumps at several of the sites, a sanitary
wastewater lagoon at one site, and other miscellaneous contamination issues is
approximately $600,000 in 2000 dollars for capital expenditures and operation
and maintenance expenses, spread over a period of 2000 to 2020.
STATUS OF PERMITS AND APPROVALS
On the basis of our review of the permits and approvals for the Plants, we
are of the opinion that the major permits and approvals required to operate the
Plants have been obtained and are currently valid, and we are not aware of any
technical circumstances that would prevent the issuance of a new FERC license
for the Missouri-Madison Plants.
Colstrip Facility
The Colstrip Facility must be operated in accordance with applicable
environmental laws, regulations, policies, codes and standards. Table 3
identifies the key permits and approvals required for the operation of the
plant.
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TABLE 3
STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
COLSTRIP FACILITY
PERMIT/APPROVAL/ RESPONSIBLE
PLAN REQUIRED FOR AGENCY STATUS COMMENTS
- --------------------- ---------------- ---------------- ---------------- -------------------------------------
FEDERAL
1. Hazardous Waste Hazardous waste USEPA/MDEQ Issued ID Nos. Large quantity generator of hazardous
Generator ID disposal MTD 000710236 wastes. Waste manifest system must be
Number tracking for Colstrip followed when disposing hazardous
Units 1 and 2 waste.
and MTD
980330609 for
Colstrip Units 3
and 4
2. Spill Prevention Oil spill USEPA/MDEQ Not required MPC determined that a plan is not
Control and prevention required because site characteristics
Countermeasure make it unlikely that any oil spills
Plan ("SPCC") could reach navigable waterways.
3. Emergency Response and USEPA/MDEQ/ Prepared Part of operating procedures manual
Response notification Local fire of plant.
Procedures procedures for department
substance
release in
accordance with
right-to-know
laws.
4. Phase II Acid Colstrip Units 1 USEPA/MDEQ Issued 12/20/95; Stack CEM data used to demonstrate
Rain Title IV and 2, SO(2) also attached to compliance with allowance allocations
Permit emissions Title V
allowance Operating Permit
program issued 11/10/98
5. Phase II Acid Colstrip Units 3 USEPA/MDEQ Issued 12/20/95. Stack CEM data used to demonstrate
Rain Title IV and 4 SO(2) Also attached to compliance with allowance allocations
Permit emissions Title V
allowance Operating Permit
program issued 10/6/97
STATE
6. Title V Operating permit MDEQ Issued 9/23/97; Incorporates all emission sources for
Operating Permit pursuant to expires 12/31/02 Colstrip Units 1 and 2 at plant.
Title V, Clean
Air Act for
Colstrip Units 1
and 2
7. Title V Operating permit MDEQ Issued 11/10/98; Incorporates all emission sources for
Operating Permit pursuant to expires 12/31/02 Colstrip Units 3 and 4 at plant.
Title V, Clean
Air Act for
Colstrip Units 3
and 4
8. Montana Wastewater MDEQ Not required Plant is designed and permitted as a
Pollutant discharges at zero discharge facility, therefore,
Discharge facility no MPDES permit is required.
Elimination
System Permit
("MPDES")
9. Certificate of Approval of Board of Natural Issued 7/22/76 Identifies conditions under which
Environmental Colstrip Units 3 Resources and Colstrip Units 3 and 4 shall be
Compatibility and 4 in Conservation constructed and operated.
and Public Need accordance with
Utility Siting
Act
10. Amendment to Modification of Board of Natural Issued 9/12/80 Allowed for more flexible operation
Certificate of Condition 12a, Resources and associated with water withdrawal from
Environmental addressing water Conservation Yellowstone River.
Compatibility withdrawal plan
and Public Need
11. Tank Underground MDEQ Issued 12/99 Issued for two 10,000-gal. tanks
Registrations storage tanks storing gasoline and diesel, 500,000-
gal. and 20,000-gal. diesel tanks.
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Corette Facility
The Corette Facility must be operated in accordance with applicable
environmental laws, regulations, policies, codes and standards. Table 4
identifies the key permits and approvals required for the operation of the
plant.
TABLE 4
STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
CORETTE FACILITY
PERMIT/APPROVAL/ RESPONSIBLE
PLAN REQUIRED FOR AGENCY STATUS COMMENTS
- --------------------- ---------------- ---------------- ---------------- -------------------------------------
FEDERAL
1. Hazardous Waste Hazardous waste USEPA/MDEQ Issued ID No. Small quantity generator of hazardous
Generator ID disposal MTD000818112 wastes. Waste manifest system must be
Number tracking followed when disposing hazardous
waste.
2. Spill Prevention Oil spill USEPA/MDEQ Prepared 7/21/95 The two 3.25 million gallon above-
Control and prevention in ground oil storage tanks were leased
Countermeasure accordance with to Conoco Oil Refinery. Conoco was
Plan ("SPCC") 40 CFR 112. responsible for managing, operating,
and monitoring the tanks. Conoco has
cleaned the tanks and they will no
longer be used to store oil.
3. Emergency Action Response and USEPA/MDEQ Prepared 8/96 Emergency Response Plan for oil
Plan notification storage tanks is included in Conoco's
procedures for Emergency Response Plan. The plant
substance also maintains a Fire Prevention
release in Plan. Tanks will no longer be used to
accordance with store oil.
right-to-know
laws.
STATE
4. Title V Operating permit MDEQ Issued 2/23/98; Incorporates all emission sources at
Operating Permit pursuant to expires plant.
Title V Clean 12/31/2003
Air Act
5. National Authorizes MDEQ Issued 4/1/00; Establishes effluent limits and
Pollutant wastewater expires 3/31/05 reporting requirements for the
Discharge discharges at various outfalls at the plant.
Elimination plant Stormwater permit not required due to
System Permit site contouring not allowing
("NPDES") discharge to the river.
6. Tank Underground MDEQ Not required No underground tanks present
Registrations storage tank on-site.
registration
Hydroelectric Facilities
The Hydroelectric Facilities are covered by four FERC licenses. Kerr Plant
(FERC No. 0005), Thompson Falls Plant (FERC No. 1869) and Mystic Plant (FERC No.
2301) have individual licenses. The remaining eight plants and the Hebgen
Reservoir are licensed as the Missouri-Madison Plants under a single license
(FERC No. 2188). There are other permits issued by the State of Montana for
operation of the various Hydroelectric Facilities.
The FERC licenses for the Hydroelectric Facilities were transferred from
MPC to PPL Montana. The Kerr Plant license expires in 2035. According to the
terms of the license, the CSKT has the right to assume control of the plant any
time between 2015 and 2025, with notice and payment of a conveyance price to PPL
Montana. Until the CSKT assumes control of the plant, the CSKT receives annual
payments from the plant and participates in plant activities. The legal record
of the Kerr Plant shows a long history of negotiation and litigation between the
CSKT and MPC regarding a variety of issues. In June 1997, FERC approved a
mitigation and management plan that could settle many of the issues related to
the Kerr Plant. The Thompson Falls Plant license expires in 2025. No noteworthy
conditions of that document were found. The Mystic Plant
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license expires in 2009. Typical natural resources and recreation issues can be
expected to arise in that relicensing process.
The Missouri-Madison Plants are currently in the process of relicensing and
are operating under annual licenses. FERC is reviewing the recommendations of
its staff, prior to issuance of the new FERC license for the Missouri-Madison
Plants. The final Environmental Impact Statement ("EIS") was issued in September
1999. The EIS contains conditions that are expected to be part of the new
license and have been included in the planning and budgets prepared by PPL
Montana. It is possible but unlikely for changes in the conditions to occur at
this point in the process. Based on the available documents, no significant new
operating restrictions are expected in the new license, and risk of substantial
unexpected mitigation costs is low.
Presently there are no fish-passage facilities at any of the Hydroelectric
Facilities. For the licensing of the Missouri-Madison Plants, fish-passage
facilities are not being prescribed by the fish resource agencies. However, the
new license will contain a standard article of condition that states that fish
passages facilities could be prescribed in the future if the fish resource
agencies determine there is a need for them. We do not expect fish passage
facilities to be required in the future because anadromous fish are not known to
reside in the upper Missouri and Madison river systems.
PPL Montana is currently studying the proposed new powerhouse at the
Rainbow Plant, and has indicated that it may decide to replace the units in the
existing powerhouse rather than construct a new powerhouse. If PPL Montana
decides to upgrade the existing powerhouse, an amendment to the new license will
be needed. However, this amendment is not expected to be difficult or expensive
to undertake since the alternative (equipment upgrade only) should have less
environmental impact than construction of a new powerhouse at a different
location.
In addition to the FERC licenses, various state permits are in place for
the Hydroelectric Facilities. These permits address water acquisition, sewage
discharge, bearing cooling water discharges, septic fields, and periodic air
permits for burning wood waste. The Hydroelectric Facilities have been in
operation for many years and none of the state permits appear to address unusual
operations or incorporate unusual conditions.
OPERATION AND MAINTENANCE
THE OPERATOR
The Plants are being operated by PPL Montana. PPL Montana's indirect
parent, PPL Generation, LLC ("PPL Generation"), currently owns and operates two
hydroelectric projects totaling 146 MW of capacity and is a one-third partner in
a 400 MW hydroelectric project with 12 operating units. It also owns and
operates 16 coal-fired units totaling over 4,000 MW capacity of which the two
largest units are each 745 MW. PPL Montana is utilizing PPL Generation's
operating experience to enhance PPL Montana's operations of the Plants and has
maintained the existing MPC operations team. PPL Montana also expects to obtain
operating efficiencies by consolidating the administrative functions for the
Plants and by managing the Colstrip and Corette Facilities together to maximize
synergies and reduce operating costs.
PPL Montana is continuing to use the MPC Colstrip Project Division, Vision
2000 Business Plan. The intent of the plan is to improve work processes and
reduce generating costs recognizing a changing utility environment. The plan
establishes budget and production levels for all four of the units. It discusses
general strategies for safety, employee satisfaction and business success that
combine to reduce cost, increase production and assure proper business focus. It
identifies specific actions to be taken by each area of budget responsibility.
Specific strategies typical of the plan include involvement of employees to
improve plant processes, extension of the period between planned outages and
reduction of the outages' durations, continued development of predictive
maintenance and the need for sound economic analysis of heat rate and generation
relationships. The plan is to undergo periodic revisions on at least an annual
basis. The 2001-2004 business plan was recently completed and approved by the
Colstrip Facility owners.
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PPL Montana has advised that it will continue to operate the Corette
Facility in a manner similar to MPC with the personnel adjustments described in
the Report section entitled Operating Programs and Procedures. The Corette
Facility is also developing a similar business plan for 2001 to 2003.
For the Hydroelectric Facilities, MPC established an operation and
maintenance approach that PPL Montana advises that it plans to continue.
OPERATING PROGRAMS AND PROCEDURES
Colstrip Facility
We have reviewed the various MPC operations and maintenance ("O&M")
programs and procedures, including: preventive, corrective and predictive
maintenance plans; operating procedures; administrative procedures; emergency
plans; training, safety and chemistry manuals and performance monitoring system.
We did not review all aspects of these plans and procedures, but verified that
all of the usual and necessary plans, procedures and documentation normally
required to operate a facility of this type were in place. PPL Montana has
advised that it accepted all MPC O&M programs and procedures in kind. Following
is a brief description of the key plans and procedures that we reviewed.
The MPC maintenance management system was called Colstrip Area Reporting
and had been utilized for the past fifteen years. It was computer based and
interfaced with the MPC main frame computer in Butte, MT. PPL Montana has
advised that it is in the process of integrating the maintenance management
system with the PPL Generation's enterprise system. It is used to control spare
parts inventory, maintaining quantities between established maximum and minimum
levels and prepares purchase orders. Preventive maintenance work orders are
scheduled and issued automatically. Corrective work orders are generated by the
operators. The system is linked to the accounting, payroll, and budgeting
system, as well.
The predictive maintenance program includes in house capability to perform
vibration based trending and uses thermography to sense hot spots in electrical
and rotating equipment. Samples of lubricating oil requiring analyses are sent
to a Mobil laboratory which returns results by electronic mail.
Electro-hydraulic control fluid is sent to the equipment vendor for analysis.
PPL Montana maintains and updates Operations and Maintenance Manuals which
include a set of operating and maintenance procedures for all major equipment
and systems at the Colstrip Facility. These manuals include original drawings
and data books from Bechtel and the various original equipment manufacturers'
operating instructions, maintenance requirements and schedules. A set of
operating procedures developed for the station is also available.
PPL Montana maintains an administrative manual and a standards and
practices manual which addresses the typical and necessary administrative
practices and procedures, including: organizational plans; accounting,
bookkeeping and record-keeping systems; personnel policies; procurement and
contracting procedures; training, safety, and site security requirements.
PPL Montana has a Safety, Training and Security Director, and there are
three safety and health advisors and two training instructors reporting to that
position. The director administers the state certified apprenticeship training
program between MPC and the International Brotherhood of Electrical Workers
("IBEW") union which represents craft personnel at the Colstrip Facility. Vendor
training and welding training, leading to welder certification, are also made
available
PPL Montana has also implemented a Safety Training Observation Program
which gives supervisors the responsibility and the training they need to prevent
injuries. It is based on observing people as they work, correcting unsafe
actions and encouraging safe practices.
While we did not undertake a detailed environmental assessment of the
operation and maintenance procedures at the Colstrip Facility, it appears that
plant personnel are aware of and are taking appropriate steps to comply with the
various environmental laws and regulations addressing hazardous waste management
and disposal, spill prevention and control, community right-to-know laws,
chemical reporting, PCBs, and asbestos.
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In conjunction with an in-house program that monitors equipment performance
trending, PPL Montana uses a computer based Plant Information ("PI") System by
OSI Software, Inc., which collects, archives, displays and disseminates process
and performance data and process variables obtained from the Colstrip Facility's
various computers and programmable logic controllers. The PI System accommodates
real-time and historic data bases and is used to develop reports and perform
monitoring and trending of equipment performance. The Colstrip Facility's PI
System is linked to the Electric Power Research Institute ("EPRI") data base.
The Colstrip Facility staffing plan consists of a total of approximately
341 personnel. This is a decrease implemented by MPC from an earlier staffing
level of approximately 600 personnel. According to plant personnel, this
decrease is due to a reorganization plan adopted by MPC three years ago.
Personnel are under either the operations and maintenance area or the business
services area. These areas are supervised by six area leaders and a consultant
leader. Each area leader is parallel to one another, however, leadership does
not function as a pyramid, as most typical generating plant organizations
operate. Area leaders are in charge of the budget for their area expenditures
and accountability. Below the area leaders are team leaders and craft leaders.
The craft personnel are organized in the IBEW union. Under the O&M Area Leader,
four O&M shift supervisors oversee the operation of the four units. Colstrip
Units 1 and 2 have eight lead plant operators, eight control room operators that
work rotating 12-hour shifts in a four shift rotation. A chemist is assigned to
each shift. Colstrip Units 3 and 4 are similarly staffed. Maintenance is
performed by craft teams, each with a leader who also reports to the O&M Area
Leader, which are responsible for specific systems or pieces of equipment.
Maintenance shifts work ten hour days, four days per week. In addition, a
small maintenance staff is assigned to each operating shift. Power Maintenance
Resources, Inc. personnel are retained on site to perform contract maintenance.
Corette Facility
We have reviewed the various MPC operations and maintenance programs and
procedures, including: preventive, corrective and predictive maintenance plans;
operating procedures; administrative procedures; emergency plans; training,
safety and chemistry manuals and performance monitoring system. We did not
review all aspects of these plans and procedures, but verified that all of the
usual and necessary plans, procedures and documentation normally required to
operate a facility of this type are in place. Following is a brief description
of the key plans and procedures which we reviewed.
The current maintenance management system is a computer-based system.
Minimal spare parts are kept on site. There is no documentation of the inventory
of spare parts; however, critical spare parts are reportedly stored on site.
Spare parts inventory and equipment histories have been entered in the system.
Preventive maintenance work order scheduling and processing have also been set
up. PPL Montana has advised that it will implement the PPL Generation "Passport"
system in the latter half of 2000.
There is no formal predictive maintenance program. However, some vibration
analysis is conducted and analyses of oil from the steam turbine, coal
pulverizers and transformers are sent out for analysis. PPL Montana reports that
development of predictive maintenance capabilities is in progress.
PPL Montana maintains and updates Operations Manuals and Maintenance
Manuals which include a set of operating and maintenance procedures for all
major equipment and systems in the plant. These manuals include original
drawings and data books from Bechtel and the various original equipment
manufacturers' operating instructions, maintenance requirements and schedules.
The plant maintains an administrative manual and a standards and practices
manual which addresses all the typical and necessary administrative practices
and procedures, including: organizational plans; accounting, bookkeeping and
record-keeping systems; personnel policies; procurement and contracting
procedures; training, safety and site security requirements. Weekly safety
meetings are conducted.
When the control room was redone in 1997 and the DCS was added, a training
room with a DCS simulator was incorporated in the layout. An audio-visual
packaged O&M training program was also purchased. The plant's practice is to
cross train operators and maintenance personnel.
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While we did not undertake a detailed environmental assessment of the
operation and maintenance procedures at the Corette Facility, it appears that
the plant's personnel are aware of and are taking appropriate steps to comply
with the various environmental laws and regulations addressing hazardous waste
management and disposal, spill prevention and control, community right-to-know
laws, chemical reporting, PCBs, and asbestos.
In 1997 the Corette Facility purchased a computer-based performance
monitoring package which is to be interfaced with the DCS and allow the
operators to model boiler and turbine cycles. It will perform on line analyses
of feedwater heater and condenser performance and has provisions for data
archiving. The system is currently in operation and being fine-tuned by the
plant's engineering staff.
Based upon our review of the stations various administrative, operating and
maintenance procedures, we are of the opinion that the Corette Facility has in
place, or plans to have in place within the next year, operating programs and
procedures which are consistent with the generally accepted practices of the
industry.
The plant staffing plan currently consists of a total of 35 personnel. A
plant superintendent is responsible for all plant functions. An operations
supervisor and a maintenance supervisor provide full-time day-to-day supervision
of the operating and maintenance staff. A plant performance analyst with three
people oversees all plant performance and efficiency reports, plus plant water
chemistry. There are four lead plant operators, four control room operators, and
eight journeyman system maintenance operators that work rotating 12-hour shifts
in a four shift rotation. The maintenance staff consists of four mechanics.
There is also a plant senior clerk and a storekeeper. All personnel have worked
in the plant for numerous years. Recently, two engineers previously on staff in
MPC's Butte, Montana offices and familiar with the Corette Facility were
transferred to the Corette Facility to follow, among other things, water
chemistry issues.
Hydroelectric Facilities
PPL Montana maintains and updates a manual entitled "Hydro Operations
Procedures" that details the general operating procedures for the Hydroelectric
Facilities as well as procedures specific to each plant. Although we did not
review all sections of the manual in detail, it appeared to contain all the
usual and necessary sections and information consistent with standard practice
at hydroelectric plants. The manual contains sections covering safety procedures
and safety training. The manual also contains sections describing procedures for
environmental reporting and action in the event of oil spills or other events
affecting the environment. PPL Montana has a General Monitoring Plan to comply
with the requirements of the FERC for maintaining and protecting the safety,
stability, and integrity of its dams, appurtenant structures, and related
equipment. This plan describes the monitoring equipment and program for each
plant and the subsequent reporting requirements.
In addition to the "Hydro Operations Procedures" manual, PPL Montana also
has an Emergency Action Plan for each hydroelectric plant. The plans are
typically required for hydroelectric projects and appear to contain information
and procedures that are consistent with standard practice.
Based on discussions of maintenance planning and procedures with the
maintenance superintendent, it was evident that careful planning for maintenance
is done, and records are kept of all maintenance activities. It appeared that
the maintenance activities are based on inspections of the plants, the
operators' observations of the units and their performance, and the age of the
plants. The Hydroelectric Facilities have a relatively low level of forced
outages, which is an indication of planned preventive maintenance over a number
of years. The plants also have an exceptionally good safety record which is also
indicative of a well trained and careful staff.
The Hydroelectric Facilities are generally staffed eight hours per day,
five days per week by a team of operators who live either in PPL Montana housing
at the plant or in the area. One of the operators is on call at all times. For
the five plants near Great Falls, the central control room at the Rainbow Plant
is staffed 24 hours per day and monitors and controls the other four plants. The
Black Eagle and Rainbow Plants have regular operators, but the Ryan, Cochrane,
and Morony Plants share operators who spend time at each plant on a daily
schedule. Table 5 lists the number of operators PPL Montana now has at each
plant.
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TABLE 5
HYDROELECTRIC FACILITIES
TOTAL OPERATING PERSONNEL
PLANT NUMBER OF OPERATORS
- ----- -------------------------
Kerr............................. 4
Thompson Falls................... 5
Mystic........................... 3
Missouri-Madison
Hebgen Reservoir............... (Madison) and 2 part time
Madison........................ 4
Hauser......................... 4
Holter......................... 4
Black Eagle.................... 2
Rainbow........................ 6
Cochrane....................... (Ryan)
Ryan........................... 4
Morony......................... (Ryan)
Total Staff.................... 36 and 2 part time
In addition to their operating duties, the operators typically handle the
housekeeping and light maintenance at each plant. For major maintenance, PPL
Montana has a maintenance staff at the Rainbow Shop located above the Rainbow
Plant that takes care of the major maintenance at all the Hydroelectric
Facilities. The Rainbow Shop has a staff of 20 people including 1
superintendent, 1 administrator, 2 warehouse clerks and 16 crafts people.
The operators and maintenance staff are supported by engineering and
regulatory personnel in Butte, Montana. According to the PPL Montana
organization chart, there are four environmental and licensing staff, six
engineers, two administrators and three managers. This staff assists with design
and contracting of projects, licensing of projects, and regulatory compliance
efforts.
Based on the condition of the Hydroelectric Facilities, their age, and the
adverse winter weather conditions, it appears that the staffing levels are
consistent with good industry practices.
SUMMARY
Based on our review, we are of the opinion that, by combining the
demonstrated experience of the current PPL Montana programs and operating team
with the operating experience of PPL Generation, PPL Montana should have
sufficient capability to operate the Plants effectively. The operating programs
and procedures which are currently in place are consistent with generally
accepted practices of the industry and, with the exception of the Colstrip
Facility, the Plants have incorporated organizational structures that are
comparable to other facilities using similar technologies. However, it appears
the Colstrip Facility personnel have successfully incorporated an organizational
structure less typical of the industry.
OPERATING HISTORY
PERFORMANCE
For the Colstrip and Corette Facilities we have prepared operating
summaries which include reported Equivalent Availability and Net Capacity
Factor. Equivalent Availability Factor is traditionally defined as the number of
hours which the unit is available to operate less the sum of (1) the equivalent
planned and unplanned derated hours and (2) the equivalent seasonal derated
hours all divided by the number of hours in the period. Net capacity factor is
defined as the net electrical generation divided by the product of the unit's
net rated capacity and the number of hours in the period.
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Colstrip Facility
Operating summaries for the past six years of operation of the Colstrip
Facility units are shown in Tables 6 through 11 and are based on data including
NERC reports provided by PPL Montana.
TABLE 6
HISTORICAL OPERATING DATA
COLSTRIP UNIT 1
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ------
Net Unit Generation (GWh)............ 1,959 2,328 2,057 2,085 2,217 2,069
Net Unit Heat Rate (Btu/kWh)......... 11,088 10,958 10,948 10,954 11,056 10,929
Net Capacity Factor (%).............. 73.1 86.9 76.5 77.5 82.4 76.9
Equivalent Availability Factor (%)... 73.4 95.0 86.2 80.8 84.4 79.2
Coal Use (Tons X 1000)............... 1,257 1,480 1,322 1,347 1,445 1,329
TABLE 7
HISTORICAL OPERATING DATA
COLSTRIP UNIT 2
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ------
Net Unit Generation (GWh)............ 2,226 2,032 2,173 2,121 2,239 2,302
Net Unit Heat Rate (Btu/kWh)......... 11,088 10,958 10,875 11,036 11,080 11,003
Net Capacity Factor (%).............. 83.1 75.8 80.8 78.9 83.3 85.6
Equivalent Availability Factor (%)... 83.8 76.6 91.6 81.9 85.3 88.3
Coal Use (Tons X 1000)............... 1,441 1,291 1,384 1,380 1,463 1,442
TABLE 8
HISTORICAL OPERATING DATA
COLSTRIP UNIT 3
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ------
Net Plant Generation (GWh)........... 5,724 4,635 3,734 4,474 5,724 5,369
Net Plant Heat Rate (Btu/kWh)........ 10,760 10,580 10,837 10,709 10,734 10,642
Net Capacity Factor (%).............. 90.8 73.5 59.0 68.6 88.3 82.8
Equivalent Availability Factor (%)... 91.7 84.5 95.5 80.1 92.1 87.4
Coal Use (Tons X 1000)............... 3,617 2,882 2,377 2,803 3,595 3,380
TABLE 9
HISTORICAL OPERATING DATA
COLSTRIP UNIT 4
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ------
Net Plant Generation (GWh)........... 5,213 4,342 3,074 4,885 5,476 5,701
Net Plant Heat Rate (Btu/kWh)........ 10,588 10,820 10,755 10,818 10,773 10,660
Net Capacity Factor (%).............. 82.7 68.8 48.6 75.4 84.5 87.9
Equivalent Availability Factor (%)... 82.8 84.9 79.9 89.9 87.2 91.1
Coal Use (Tons X 1000)............... 3,241 2,760 1,942 3,092 3,452 3,595
Based upon the operating history of the Colstrip Facility, we are of the
opinion that each of Colstrip Units 1 and 2 should be capable of delivering net
electrical capacity of 307 MW at a full load net heat rate of 11,124
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Btu/kWh and that each of Colstrip Units 3 and 4 should be capable of delivering
a net electrical capacity of 740 MW at a full load net heat rate of 10,459
Btu/kWh.
Corette Facility
An operating summary for the past six years of operation of the Corette
Facility is shown below in Table 10 and are based on data provided by PPL
Montana.
TABLE 10
HISTORICAL OPERATING DATA
CORETTE FACILITY
1994 1995 1996 1997 1998 1999
------ ------ ------ ------ ------ ------
Net Plant Generation (GWh)........... 1,177 1,138 1,043 737 595 1,066
Net Plant Heat Rate (Btu/kWh)........ 11,279 11,225 10,891 11,049 11,052 10,981
Capacity Factor (%).................. 86.1 83.3 76.1 53.9 43.7 78.2
Equivalent Availability Factor (%)... 89.0 86.9 83.6 57.7 43.8 79.1
Coal Use (Tons X 1000)............... 703 693 680 484 396 674
Based upon the operating history of the Corette Facility, we are of the
opinion that it should be capable of delivering a net electrical capacity of 154
MW at an average annual net heat rate of 11,100 Btu/kWh.
Hydroelectric Facilities
For the Hydroelectric Facilities we have prepared operating summaries which
include reported Availability Factor and Capacity Factor. Availability Factor is
traditionally defined as the number of hours which the plant is available to
operate divided by the number of hours in the period. Capacity Factor is defined
as the net electrical generation divided by the product of the plant's rated
capacity and the number of hours in the period.
TABLE 11
HISTORICAL OPERATING DATA
HYDROELECTRIC FACILITIES
1993-1999 1993-
TOTAL AVERAGE ANNUAL PLANT 1997(1)
NO. OF CAPACITY GENERATION CAPACITY AVAILABILITY
PLANT UNITS (MW) (GWH) FACTOR FACTOR
- ----- ------ -------- ---------------- -------- ------------
Kerr................................ 3 189 1,144.0 69.1 91.3
Thompson Falls...................... 7 86 538.1 71.4 97.5(2)
Mystic Lake......................... 2 11 50.6 52.6 99.0
Madison............................. 4 9 59.1 74.9 87.5
Hauser.............................. 6 17 147.4 99.0 96.4
Holter.............................. 4 50 325.9 74.4 92.0
Black Eagle......................... 3 18 137.1 87.0 94.5
Rainbow............................. 8 35 252.5 82.3 98.2
Cochrane............................ 2 54 332.1 70.2 98.6
Ryan................................ 6 60 453.4 86.3 98.1
Morony.............................. 2 48 333.2 79.2 98.2
--- ------- ----
Total..................... 577 3,773.5 74.7
- ---------------
(1) Data not recorded by MPC after 1997.
(2) For the Thompson Falls Plant, Units 1 through 6 only.
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Projections of the future energy from the Hydroelectric Facilities were
prepared by PPL Montana with the assistance of its hydroelectric consultant. We
reviewed the estimates with regard to the general approach, methodology, and
input data to determine if normal industry standards were followed and if the
results appeared to be adequate for the purposes of this Report. We did not
perform independent power studies.
The Hydroelectric Facilities are located on streams that have extensive
long-term stream flow gage records. The Kerr, Thompson Falls, Mystic, Madison
and Holter Plants have gages that are located downstream from the tailraces. As
run-of-river plants, the flows recorded by the gages include power flows, spills
and any required bypass flows. The gage data is, therefore, a reliable record of
available inflow to each of those plants. The available flow for the remaining
Hydroelectric Facilities can be estimated by multiplying the gage data by a
ratio of the drainage area at each plant and at the appropriate gage.
Historic flow data for the gages were obtained from the United States
Geological Survey data files for the available periods of record. These were
reviewed for length of record, consistency and seasonal and annual variations.
The period selected by PPL Montana for the energy analysis contained a number of
high and low flow years.
The Hydroelectric Facilities performance and outages were accounted for in
the analysis by using a combined efficiency curve for each Hydroelectric Plant,
which is consistent with industry standards. PPL Montana selected 30 years to
estimate the potential energy for the Hydroelectric Facilities.
PPL Montana assumed average availability factors of 90.2 percent. It should
be noted that the electricity generation of hydroelectric facilities is impacted
by both availability and water inflow to the facility. The capacity factors
projected by PPL Montana are lower than the assumed availability since the
Hydroelectric Facilities are assumed to be available to operate at times when
the water inflow is not available.
Based on the review, we are of the opinion that the methodology used by PPL
Montana to estimate energy from the Hydroelectric Facilities using historical
streamflow records is consistent with industry standards.
REGULATORY COMPLIANCE
Colstrip Facility
Air Compliance
The major permit regulating the Colstrip Facility's air emissions is the
Title V Operating Permit. The permit for Colstrip Units 1 and 2 was issued
September 23, 1997 and became effective January 1, 1999. The permit for Colstrip
Units 3 and 4 was issued November 10, 1998 and became effective January 1, 1999.
The permits contain specific emission limits and monitoring requirements as well
as other conditions that must be complied with during the operation of the
plant.
Table 12 presents the key emission limits for Colstrip Units 1 and 2
boilers.
TABLE 12
AIR EMISSION LIMITS
COLSTRIP UNITS 1 AND 2
POLLUTANT EMISSION LIMIT
- --------- --------------
SO(2) (lb/MMBtu) 1.2 (3-hr rolling avg.)
SO(2) (% sulfur in coal) 1
NO(X) (lb/MMBtu) 0.7 (3-hr rolling avg.)
0.45 (annual avg. as per Title IV
Acid Rain Permit)
Particulate Matter (lb/MMBtu) 0.1
Opacity (%) 20, except one six min. avg. of not
more
than 27 percent
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Table 13 presents the key emission limits for Colstrip Units 3 and 4
boilers.
TABLE 13
AIR EMISSION LIMITS
COLSTRIP UNITS 3 AND 4
POLLUTANT EMISSION LIMIT
- --------- --------------
SO(2) (lb/MMBtu) 0.18 (calendar day avg.)
SO(2) (pph) 761 (30-day rolling avg.)
1,363 (calendar day avg.)
4,273 (3-hr rolling avg.)
SO(2) (% sulfur in coal) 1
NO(X) (lb/MMBtu) 0.7 (3-hr rolling avg.)
0.45 (annual avg. as per Title IV
Acid Rain Permit)
NO(X) (pph) 5301(3-hr rolling avg.)
Particulate Matter (lb/MMBtu) 0.05 (3-hr test)
Particulate Matter (pph) 379 (3-hr test)
Opacity (%) 20, except one six min. avg. of not
more
than 27 percent
Heat Input (MMBtu/yr) 6.63 (LOGO) 10(7)
Table 14 presents the 1996, 1997, 1998, and 1999 annual averages of SO(2)
and NO(X) emissions for the Colstrip units.
TABLE 14
ANNUAL AVERAGE AIR EMISSIONS
COLSTRIP FACILITY
(lb/MMBtu)
1996 1997 1998 1999
------------- ------------- ------------- -------------
UNIT SO(2) NO(X) SO(2) NO(X) SO(2) NO(X) SO(2) NO(X)
- ---- ----- ----- ----- ----- ----- ----- ----- -----
1 0.377 0.381 0.414 0.373 0.393 0.386 0.444 0.410
2 0.353 0.380 0.425 0.384 0.452 0.408 0.404 0.370
3 0.078 0.350 0.088 0.390 0.092 0.408 0.101 0.430
4 0.078 0.356 0.096 0.391 0.094 0.415 0.102 0.450
The number of exceedances reported were typical of units of this type with
which we are familiar and do not represent a trend of long term noncompliance
with the emission limits set forth in the Title V Permit.
The Colstrip Facility units are subject to the Acid Rain Program as Phase
II affected units relative to SO(2) emissions. As such, the Acid Rain Program
requires that affected emission sources possess sufficient SO(2) allowances to
cover their actual emissions beginning in the year 2000. MPC was allocated a
number of allowances by the United States Environmental Protection Agency
("USEPA") as part of the Acid Rain Program for years 2000 to 2009 and for years
2010 and beyond. As part of the Asset Purchase Agreement, PPL Montana acquired a
portion of MPC's originally allocated SO(2) allowances for the Colstrip Facility
equal to 5,795 tons per year through 2025.
Actual annual emissions for the entire Colstrip Facility during 1996, 1997,
1998 and 1999 were 10,755, 14,577, 18,003 and 17,948 tons, respectively. It
should be noted that the Colstrip units have scrubbers that can potentially be
operated to a higher level of control, therefore, allowing a certain level of
flexibility in the operation to match the number of allowances controlled by PPL
Montana. The exact number of allowances that will be required in the future will
depend to a large extent on the future utilization rates. PPL Montana
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will be obligated to supply allowances in proportion to its ownership interest
in Colstrip Units 3 and 4. Allowances from the Colstrip and Corette Facilities
can be transferred between the units at either plant.
PPL Montana is involved in ambient monitoring at various sites in proximity
to the Colstrip Facility. PPL Montana operates three monitoring sites that
monitor SO(2), NO(X) and a variety of meteorological parameters. PPL Montana is
also financially obligated to support a monitoring program for particulate
matter of 10 microns or less ("PM(10)") on the Northern Cheyenne Indian
Reservation (the "Northern Cheyenne"). The sites are operated by the Northern
Cheyenne. PPL Montana provides quality control and technical assistance to the
Northern Cheyenne, and pays a $75,000 fee and a $25,000 grant per year to
support the monitoring efforts of the Northern Cheyenne. No significant problems
have been identified with the ambient monitoring program.
Certain future requirements relative to the revised particulate matter of
2.5 microns or less ("PM(2.5)") standard, the haze rule, regional visibility,
and potential ratcheting of the SO(2) allowance program beyond the year 2009 may
affect the Colstrip Facility in the future by imposing more stringent
requirements than those in effect at the present time. Based on available data
for PM(10) the USEPA identified Rosebud County as potentially exceeding the new
PM(2.5) standard. However, the USEPA has indicated that future designations are
speculative and will be confirmed by ambient monitoring conducted between 1998
and 2004. Due to concerns by industry, the USEPA agreed to reevaluate the
standard no later than 2002 prior to designating any non-attainment areas. State
Implementation Plan revisions for PM(2.5) would be due at the earliest 2005. In
addition, PM(2.5) is viewed as a regional problem, i.e., particulate
non-attainment in Rosebud County may be caused by distant sources. Because of
the extended compliance schedule, future emission reduction requirements that
may be imposed on the Colstrip Facility, if any, cannot be determined at the
present time.
The compliance history of the Colstrip Facility can be categorized as good.
It is not presently operating under any Consent Orders resulting from Notices of
Violations ("NOVs"). In 1997 the Colstrip Facility was issued an NOV for failing
to recover a minimum percentage of data from one of the ambient monitoring sites
in Colstrip. The penalty for this NOV has been identified to pave a road in the
Town of Lame Deer on the Northern Cheyenne Indian Reservation at an estimated
cost of less than $50,000. The road has been paved and the NOV was deemed closed
by the MDEQ in December 1999. Additionally, during 1997 an NOV was issued for
late submittal of the Certification Report for the CEMS. MPC did not expect a
fine to be issued as a result of this NOV and none has been issued to date.
Wastewater Compliance
The Colstrip Facility is being operated as a zero discharge facility. A
pond network is utilized for water management to recycle cooling water and
process wastewater from the ponds to the plant for reuse. Monitoring wells have
been installed around the ponds to monitor ground water as a result of pond
seepage. MPC prepared annual reports for submittal to the MDEQ describing the
results of the monitoring. Impacts to groundwater as a result of seepage have
occurred. In order to control the migration of the seepage plumes, groundwater
collection systems have been installed using either recovery wells or trenches
with the recovered seepage returned to an active pond. Approximately 34 recovery
systems consisting of recovery wells, sumps, and trenches have been installed to
abide with the State of Montana's mandate requiring no degradation of
groundwater quality.
Eventually, all ponds that comprise the water management system at the
Colstrip Facility will require closure following their useful life, either
during or after the plant's useful life. As is the case with previously closed
ponds, appropriate measures will need to be taken to ensure the integrity of the
closed ponds. While pond seepage concerns are environmental in nature,
addressing the concerns has financial implications on operation and maintenance
budgets as discussed under the Environmental Site Assessments section of this
Report.
Two NOVs have been issued to the Colstrip Facility for adverse impacts
associated with pond seepages in 1998. An NOV was issued in August 1998 for a
seepage collection system failure for the Colstrip Units 3 and 4 effluent
holding pond main sump pump. An additional NOV was issued in August 1998 for
pond seepage in many areas of plant ponds. This has been addressed by the
installation of additional collection systems to
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intercept the seepages from the ponds. The MDEQ has not formally responded as to
the adequacy of the recovery systems and, hence, PPL Montana is proceeding on
the presumption that their efforts in installing the recovery system are
adequate to address these NOVs.
The MDEQ issued a March 8, 2000 letter indicating that a spill of fly ash
effluent return water which occurred at Colstrip Units 3 and 4 effluent pipeline
drain pond No. 3 constituted a violation of the terms of the Certificate of
Environmental Compatibility and Public Need. An original penalty of $11,400 was
assessed for the violation. PPL Montana subsequently revised the quantity of
effluent spilled and on April 21, 2000, the MDEQ issued a Notice of Violation
and Administrative Order of Consent with a lowering of the original $11,400 fine
to $3,800. At the present time, PPL Montana is considering the MDEQ offer.
A Violation Letter was issued January 27, 2000 by the MDEQ for a
transformer cooling oil spill that occurred in September 1999. There was no fine
or penalty imposed. PPL Montana developed a remediation plan of action. Based on
our contacts with the MDEQ, it is in basic agreement with the remediation plan.
A Violation Letter was issued by the MDEQ on February 29, 2000 for seepage
from the Colstrip Units 3 and 4 effluent holding pond on the hillside below the
saddle dam. No fines or penalties were issued to date and PPL Montana does not
expect any to be issued for this Letter of Violation.
Corette Facility
Air Compliance
The major permit regulating the Corette Facility's air emissions is the
Title V Operating Permit. The permit was issued February 23, 1998 and became
effective January 1, 1999. The permit contains specific emission limits and
monitoring requirements as well as other conditions that must be complied with
during the operation of the plant.
Table 15 presents the key emission limits for the Corette Facility.
TABLE 15
AIR EMISSION LIMITS
CORETTE FACILITY
POLLUTANT EMISSION LIMIT
- --------- --------------
SO(2) (lb/yr) 9,999,000
SO(2) Calculated limits (3-hr and daily
emissions)
SO(2) (sulfur in fuel, lb/MMBtu) 1
NO(X) (lb/MMBtu) 0.4 (annual avg.)
effective 1/1/2000
Particulate Matter(lb/MMBtu) 0.26 (3-hr test)
Opacity (%) 23 (1-hr avg.)
17 (24-hr avg.)
Buoyancy Flux 144.6 - 448.57 m(4)/sec(3)
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Table 16 presents the 1996, 1997 and 1998 annual averages of SO(2) and
NO(X) for the Corette Facility.
TABLE 16
ANNUAL AVERAGE AIR EMISSIONS
CORETTE FACILITY
(lb/MMBtu)
1996 1997 1998 1999
- ------------ ------------- ------------- -------------
SO(2) NO(X) SO(2) NO(X) SO(2) NO(X) SO(2) NO(X)
- ----- ----- ----- ----- ----- ----- ----- -----
0.763 0.441 0.451 0.312 0.429 0.272 0.455 0.250
The number of exceedances reported to us were typical of plants of this
type with which we are familiar and do not represent a trend of long term
noncompliance with the emission limits set forth in the Title V Permit.
The Corette Facility is subject to the Acid Rain Program as a Phase II
affected unit relative to SO(2) emissions. As such, the Acid Rain Program
requires that affected emission sources possess sufficient SO(2) allowances to
cover their actual emissions beginning in the year 2000. MPC was allocated a
number of allowances by the USEPA as part of the Acid Rain Program for years
2000 to 2009 and for years 2010 and beyond. As part of the Asset Purchase
Agreement, PPL Montana acquired a portion of MPC's originally allocated SO(2)
allowances for the Corette Facility equal to 4,312 tons per year through 2025.
Annual emissions from the plant during 1996, 1997, 1998 and 1999 were
4,312, 1,925, 1,536 and 2,698 tons, respectively. The exact number of allowances
that will be required in the future will depend to a large extent on the fuel
used and the future utilization rates of the Corette Facility.
The Billings/Laurel area is in non-attainment for SO(2). The USEPA has
required the MDEQ to revise its State Implementation Plan to put into place
limits that bring the area into attainment status with federal SO(2) ambient air
quality standards. Other parties involved in negotiating the terms of the State
Implementation Plan include Cenex, Conoco, Exxon, Montana Sulfur and Chemical,
and Western Sugar. PPL Montana is also obligated to participate in an ambient
monitoring program in the area. The key stipulations in the State Implementation
Plan affecting the Corette Facility include: a 3-hour SO(2) emission limit that
varies with buoyancy flux; a calendar day SO(2) emission limit not to exceed the
sum of the 3-hour values; and buoyancy flux limit to a minimum of 144
m(4)/sec(3) and a maximum of 448.57 m(4)/sec(3).
As indicated under the Report section describing the regulatory compliance
for the Colstrip Facility, certain future requirements relative to the revised
PM(2.5) standard, the haze rule, regional visibility, and potential ratcheting
of the SO(2) allowance program beyond the year 2009 may affect the Corette
Facility in the future by imposing more stringent requirements than those in
effect at the present time. Because of the extended compliance schedule, and
future emission reduction requirements that may be imposed on the Corette
Facility, if any, cannot be determined at the present time.
The compliance history of the Corette Facility can be categorized as good
and it was not issued any recent NOVs. The Corette Operating Permit indicates an
ongoing matter related to a past problem with particulate emissions that
resulted in a NOV during 1985. No recent NOVs have been issued associated with
particulate emissions at the Corette Facility.
Wastewater Compliance
A Montana Pollutant Discharge Elimination System ("MPDES") Permit regulates
the Corette Facility's wastewater effluents. Unlike the Colstrip Facility, the
Corette Facility is not a zero discharge facility, and has three permitted
discharges to the Yellowstone River. The three discharges are for the former
Bird Plant cooling water, Corette Facility cooling water, and the bottom ash
pond discharge. The renewal of the MDPES was issued on April 1, 2000.
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Based on our plant visit and review of the monthly monitoring reports for
1999, the discharges were found to be in compliance. The sample results for
toxicity for 1999 were satisfactory and met permit conditions. Nothing was
identified that appears to be a long-term noncompliance concern.
Although the Corette Facility cooling water intake is the primary intake
used at the plant, the former Bird Plant intake is also used seasonally. During
the winter, water is pumped from the Corette Facility discharge to the Bird
Plant discharge (upstream) to prevent ice formation in the river in order to
keep the Corette plant intake clear of ice. In addition, water from the Bird
Plant intake is diverted to the Corette Facility discharge to lower its
temperature before discharging to the Yellowstone River to comply with the 110
degreesF limit. According to plant personnel this is not a standard practice but
one that is performed periodically and it has reportedly not been detrimental to
plant operations.
Hydroelectric Facilities
No significant compliance problems were found at any of the Hydroelectric
Facilities. Aside from infrequent issues of delayed submittals or temporarily
unmet minimum flow requirements, the only compliance issue involved MPDES
permits for cooling water at ten of the plants. This concern was identified by
PPL Montana at Black Eagle, Cochrane, Hauser, Holter, Kerr, Madison, Morony,
Mystic, Rainbow and Ryan Plants. However, the MDEQ is fully aware of the
situation and apparently unconcerned about the minor discharges. Furthermore,
the costs associated with achieving compliance if that becomes necessary are
small, and there is no apparent record of the MDEQ seeking to impose penalties
although the situation has been known for several years.
Summary
Based on our plant visits and review of documents, data and monitoring
reports, we are of the opinion that the Plants appear to be operating in general
compliance with applicable environmental permits, approvals, laws, rules and
regulations.
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In the preparation of this Report and the opinions that follow, we have
made certain assumptions with respect to conditions which may exist or events
which may occur in the future. While we believe these assumptions to be
reasonable for the purpose of this Report, they are dependent upon future
events, and actual conditions may differ from those assumed. In addition, we
have used and relied upon certain information provided to us by sources which we
believe to be reliable. While we believe the use of such information and
assumptions to be reasonable for the purposes of our Report, we offer no other
assurances thereto and some assumptions may vary significantly due to
unanticipated events and circumstances. To the extent that actual future
conditions differ from those assumed herein or provided to us by others, the
actual results will vary from those projected herein. This Report summarizes our
work up to the date of the Report. Thus, changed conditions occurring or
becoming known after such date could affect the material presented to the extent
of such changes.
The principal considerations and assumptions made by us and the principal
information provided to us by others include the following:
1. As Independent Engineer, we have made no determination as to the
validity and enforceability of any contract, agreement, rule, or regulation
applicable to the Montana Portfolio and its operations. However, for
purposes of this Report, we have assumed that all such contracts,
agreements, rules, and regulations will be fully enforceable in accordance
with their terms and that all parties will comply with the provisions of
their respective agreements.
2. Our review of the design of the Montana Portfolio was based on
information developed by MPC and PPL Montana.
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3. The operators will maintain the Plants in accordance with good
engineering practice, will perform all required major maintenance in a
timely manner, and will not operate the equipment to cause it to exceed the
equipment manufacturers' recommended maximum ratings.
4. The operators will employ qualified and competent personnel and
will generally operate the Plants in a sound and businesslike manner.
5. Inspections, overhauls, repairs and modifications are planned for
and conducted in accordance with manufacturers' recommendations, and with
special regard for the need to monitor certain operating parameters to
identify early signs of potential problems.
6. All licenses, permits and approvals, and permit modifications
necessary to operate the Plants have been, or will be, obtained on a timely
basis and any changes in required licenses, or permits and approvals will
not require reduced operation of, or increased costs to, the Plants.
CONCLUSIONS
Set forth below are the principal opinions we have reached after our review
of the Montana Portfolio. For a complete understanding of the estimates,
assumptions, and calculations upon which these opinions are based, the Report
should be read in its entirety. On the basis of our review and analyses of the
Montana Portfolio and the assumptions set forth in this Report, we are of the
opinion that:
1. The sites for the Plants are suitable for the Plants' continued
operation.
2. The Plants have been designed and constructed in accordance with
good engineering practices and generally accepted industry practices and
the technologies in use at the Plants are sound, proven conventional
methods of electric and thermal generation. Furthermore, all major off-site
requirements of the Plants are adequately provided for, including coal
supply, water supply, and electrical interconnections. If operated and
maintained as they are currently, the Plants should be capable of meeting
the currently applicable environmental permit requirements.
3. The Colstrip Transmission System utilizes sound technology and
proven methods of electric transmission and has generally been designed and
constructed in accordance with generally accepted industry practices.
4. Colstrip Units 1, 2, 3 and 4 and the Corette Facility should be
capable of achieving annual average equivalent availability factors of
87.9, 84.9, 88.7, 86.3 and 85.7 percent, respectively, over the term of the
Certificates. There will be years when the availability is both above and
below the projected annual average.
5. The Plants and the Colstrip Transmission System should have a
useful life extending well beyond the term of the Certificates.
6. The dam safety inspection reports for the Hydroelectric Facilities
were conducted in a manner consistent with industry standards, using
comparable industry protocols for similar studies with which we are
familiar.
7. The environmental site assessments and subsurface investigations
of the sites for the Plants were conducted in a manner consistent with
industry standards, using comparable industry protocols for similar studies
with which we are familiar.
8. The major permits and approvals required to operate the Plants
have been obtained and are currently valid, and we are not aware of any
technical circumstances that would prevent the issuance of a new FERC
license for the Missouri-Madison Plants.
9. By combining the demonstrated experience of the current PPL
Montana programs and operating team with the operating experience of PPL
Generation, PPL Montana should have sufficient capability to operate the
Plants effectively. The operating programs and procedures which are
currently in place are consistent with generally accepted practices of the
industry and, with the exception of the
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Colstrip Facility, the Plants have incorporated organizational structures
that are comparable to other facilities using similar technologies.
However, it appears the Colstrip Facility personnel have successfully
incorporated an organizational structure less typical of the industry.
10. Based on the operating history, proposed operation and
maintenance practices, observed conditions and proposed capital
expenditures:
(a) Each of Colstrip Units 1 and 2 should be capable of delivering
net electrical capacity of 307 MW at a full load net heat rate of 11,124
Btu/kWh.
(b) Each of Colstrip Units 3 and 4 should be capable of delivering
net electrical capacity of 740 MW at a full load net heat rate of 10,459
Btu/kWh.
(c) The Corette Facility should be capable of delivering net
electrical capacity of 154 MW at an annual average net heat rate of
11,100 Btu/kWh.
11. The methodology used by PPL Montana to estimate energy from the
Hydroelectric Facilities using historical streamflow records is consistent
with industry standards.
12. The Plants appear to be operating in general compliance with
applicable environmental permits, approvals, laws, rules and regulations.
Respectfully submitted,
/s/ R. W. BECK, INC.
--------------------------------------
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APPENDIX B: INDEPENDENT MARKET CONSULTANT'S REPORT
B-1
206
INDEPENDENT MARKET EXPERT REPORT
FOR THE NORTHWEST POWER MARKETS
Final Report
Prepared for:
Chase Securities Inc.
Prepared by:
PHB Hagler Bailly, Inc.
May 23, 2000
207
DISCLAIMER
This report presents PHB Hagler Bailly, Inc.'s (PHB Hagler Bailly) analysis
of the Western Systems Coordinating Council -- Northwest power market.
(i) some information in the report is necessarily based on predictions
and estimates of future events and behaviors,
(ii) such predictions or estimates may differ from that which other
experts specializing in the electricity industry might present,
(iii) the provision of a report by PHB Hagler Bailly does not obviate
the need for potential investors to make further appropriate inquiries as
to the accuracy of the information included therein, or to undertake an
analysis of its own,
(iv) this report is not intended to be a complete and exhaustive
analysis of the subject issues and therefore will not consider some factors
that are important to a potential investor's decision making, and
(v) PHB Hagler Bailly and its employees cannot accept liability for
loss suffered in consequence of reliance on the report. Nothing in PHB
Hagler Bailly's report should be taken as a promise or guarantee as to the
occurrence of any future events.
208
CONTENTS
EXECUTIVE SUMMARY
S.1 Introduction................................................ S-1
S.2 Market Characteristics...................................... S-1
S.3 Forecasting Methodology..................................... S-2
S.4 Key Assumptions............................................. S-2
S.5 Results and Conclusions..................................... S-3
CHAPTER 1 INTRODUCTION
1.1 Objective................................................... 1-1
1.2 Asset Description........................................... 1-1
1.3 Structure of the Report..................................... 1-1
CHAPTER 2 MARKET STRUCTURES IN THE WSCC
2.1 Introduction................................................ 2-1
2.2 Competitive Power Markets................................... 2-1
2.2.1 Reliability and Competitive Markets................... 2-3
2.3 Northwest Market............................................ 2-5
2.3.1 Overview.............................................. 2-5
2.3.2 The Northwest Power Pool.............................. 2-5
2.3.3 Retail Customer Direct Access......................... 2-5
2.3.4 Significance of Hydropower............................ 2-6
2.3.5 Bonneville Power Administration....................... 2-6
2.3.6 Development of Regional Transmission Organizations.... 2-7
2.4 California.................................................. 2-7
2.4.1 Market Structure in California........................ 2-8
CHAPTER 3 APPROACH TO MARKET PRICE FORECASTING
3.1 Introduction................................................ 3-1
3.2 Issues in Forecasting Market Prices......................... 3-1
3.2.1 Economic Equilibrium and Market Price Forecasting..... 3-1
3.2.2 Capacity and Energy Markets........................... 3-1
3.2.3 Forecasting Generation Service Prices................. 3-3
3.3 Approach to Market Price Forecasting........................ 3-4
3.3.1 Market Characteristics................................ 3-5
3.3.2 Predicting Energy Prices and Dispatch................. 3-5
3.3.3 Predicting Prices Related to Capacity:
The Capacity Compensation Simulation Model.................. 3-6
3.3.4 Market Entry and Exit................................. 3-6
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CHAPTER 4 ASSUMPTIONS
4.1 Introduction................................................ 4-1
4.2 General Assumptions......................................... 4-1
4.3 Pricing Areas............................................... 4-1
4.4 Fuel Prices................................................. 4-2
4.4.1 Natural Gas........................................... 4-2
4.4.2 Fuel Oil.............................................. 4-5
4.4.3 Coal.................................................. 4-7
4.5 Demand and Energy Forecasts................................. 4-8
4.6 Electricity Imports......................................... 4-9
4.7 Existing Generation Units................................... 4-9
4.7.1 Fossil Units.......................................... 4-9
4.7.2 Hydroelectric Units................................... 4-10
4.7.3 Nuclear Units......................................... 4-11
Capacity Compensation Market Simulation Model Input
4.8 Assumptions................................................. 4-12
4.8.1 Existing Units Going-Forward Costs.................... 4-12
4.8.2 Capacity Additions Through 2002....................... 4-12
4.8.3 Capacity Additions Post 2002.......................... 4-14
CHAPTER 5 MARKET PRICE FORECASTS
5.1 Introduction................................................ 5-1
5.2 Northwest Market Conditions................................. 5-2
5.2.1 Base Case Analysis.................................... 5-3
5.2.2 Montana Energy and All-In Price Forecast.............. 5-4
5.2.3 Washington Oregon East................................ 5-5
5.2.4 Washington Oregon West................................ 5-6
5.3 Sensitivity Cases........................................... 5-8
5.3.1 Montana Energy and All-In Price Forecasts Sensitivity
Cases....................................................... 5-9
5.3.2 Washington Oregon East Energy and All-In Price
Forecasts Sensitivity Cases................................. 5-11
5.3.3 Washington Oregon West Energy and All-In Price
Forecasts Sensitivity Cases................................. 5-13
APPENDICES:
A REGIONAL COAL PRICE FORECASTS............................... A-1
B TRANSFER CAPABILITY......................................... B-1
C NEW CAPACITY ADDITIONS...................................... C-1
D SUPPLY CURVES............................................... D-1
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EXECUTIVE SUMMARY
S.1 INTRODUCTION
PHB Hagler Bailly, Inc. (PHB Hagler Bailly) was retained by Chase
Securities Inc. (Chase Securities) to independently assess future prices for
electric energy and related products in the Western Systems Coordinating
Council -- Northwest market in support of a financing of PPL Montana's
acquisition of generating assets from Montana Power Company.
The portfolio of assets includes coal-fired generation and hydro
generation. The coal-fired generation includes the 154 MW (net) Corette power
plant and PPL Montana's share of Colstrip Units 1 through 3 (529 MW net). The
hydro generation consists of 577 MW (net) of run-of-river hydro generation.
S.2 MARKET CHARACTERISTICS
The United States is currently experimenting with a variety of regional
market structures. Some regions currently have fixed reserve margin requirements
coupled with capacity markets, while others implicitly price capacity through
on-peak energy prices, ancillary service prices, and bilateral option contracts.
In addition, some regions have developed bid-based markets for the provision of
energy, ancillary services, and/or capacity, while others continue to rely on
bilateral contracts. It is not clear which model will eventually become more
widespread. Nevertheless, in both types of markets, new generating capacity will
be developed based on the revenue streams determined through competition. While
the type of market in place in a given region will determine the composition of
the revenue streams and will affect the mix and timing of new generating units,
the financial return on new assets is likely to be similar in both types of
markets, as generators seek to cover their total going-forward costs.
The Western Systems Coordinating Council (WSCC) consists of 78 member power
systems and 21 affiliates in 14 states. These states include Arizona,
California, Colorado, Idaho, Nevada, Oregon, Utah, Washington, Wyoming, parts of
Montana, Nebraska, New Mexico, South Dakota, Texas, part of northwestern Mexico,
and Alberta and British Columbia, Canada. Currently, the only centrally
organized competitive wholesale power market in the WSCC-U.S. is in California.
The generator services market for the remaining portion of the region is
primarily based on bilateral wholesale contracts.
The WSCC consists of approximately 59 million electricity consumers with
more than 700,000 GWh of annual consumption. Over 40% of the installed capacity
in the region is hydro generation. Oil-fired and gas-fired generation represent
almost 30% of the installed capacity. Over 20% of the installed capacity is
coal-fired generation. A relatively small portion of the capacity, approximately
6%, is nuclear generation. The annual energy demand in the WSCC is projected to
grow at approximately 1.5%.
The Northwest, consisting of Montana, Washington, Oregon, and Idaho,
represents the primary market for power for the acquired facilities. The
Northwest generator services market is primarily based on bilateral contracts.
However the market also includes two informal spot markets with survey data
reported daily (California-Oregon Border [COB] and Mid-Columbia), a formal
short-term/spot market (APX/Chelan Mid-Columbia), and a formal futures market
(the NYMEX COB futures market). There are currently no markets for ancillary
services, other than bilateral contracts. Utilities in the Northwest are members
of the Northwest Power Pool (NWPP), a voluntary reserve group. Retail customer
direct access is limited in the region. Because of the mild climate, the region
is strongly winter peaking. The market is unique in the United States in its
reliance on hydropower. Almost 70% of the installed capacity in the region is
hydro generation that represents approximately 60% of the annual energy
generation in the region (based on the average of the last 10 years of hydro
generation). Coal-fired generation is the second largest component representing
approximately 18% of the installed capacity and 26% of the annual energy
generation. There is a relatively small amount of nuclear generation in the
region, approximately 2% to 3% of installed capacity and annual generation.
Natural gas and oil comprise approximately 8% to 9% of the installed capacity
and annual generation. The market is also characterized by the dominance of one
transmission owner, the Bonneville Power Administration (BPA). The annual energy
demand in the Northwest is projected to grow at approximately 1%.
S-1
211
S.3 FORECASTING METHODOLOGY
A fundamental tenant of PHB Hagler Bailly's market price forecasting
approach is that markets are attempting to adjust to economic equilibrium
conditions. By economic equilibrium, we mean that the market will attempt to
exploit or capture excess margins through entry (e.g., when the return on equity
is above market), and will attempt to increase margins where they are below
market through exit. In other words, excess returns should not persist because
someone will enter to capture a portion of the above market return.
The structure of U.S. electric markets is evolving. Some electricity
markets provide separate compensation for energy and capacity. Other electricity
markets are energy only markets, and do not separately pay generators for their
installed capacity. While the type of market in place in a given region will
determine the composition of the revenue stream and will affect the mix and
timing of new generating units, the financial return on new assets is likely to
be similar in both types of markets as generators seek to cover their total
going-forward costs.
PHB Hagler Bailly produces forecasts of generation service prices by
examining two components of value in our fundamental model:
- Energy prices reflecting the marginal cost in each hour based on a
production-cost model.
- Compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market. This
compensation for capacity is not the same as a capacity price in a traded
capacity market.
From the energy price analysis, PHB Hagler Bailly determines the net energy
margins (price minus variable cost) for each generating unit in the market.
These margins, along with estimates of "going-forward costs," are used in the
Capacity Compensation Simulation Model to predict the additional margins related
to the provision of capacity. This model presumes that the market will retain a
sufficient amount of capacity to meet economic reliability targets. In other
words, PHB Hagler Bailly simulates a capacity market consisting of a supply
curve and a demand curve for reliability (or capacity) services. PHB Hagler
Bailly assumes a competitive market, and that the market-clearing compensation
for capacity is determined by the intersection of the supply and demand curves.
PHB Hagler Bailly constructs supply and demand curves for each year in the
simulation time horizon.
Compensation for capacity may take many forms. Payments could be in the
form of a capacity price arising from a capacity market, a regulated payment
fee, bilateral contracts, payments by an ISO for ancillary services, or in the
form of prices above the marginal cost of the price-setting plant. Regardless of
the form, compensation for capacity will be set to a level necessary to retain a
stated minimum amount of generation capacity in the market. Ultimately, the
compensation for capacity will reflect what customers are willing to pay for
system reliability. The total market price, namely the sum of the energy price
plus adequate compensation for capacity, is represented in the report by the
all-in market price for electricity.
S.4 KEY ASSUMPTIONS
The key assumptions in this analysis include demand growth, fuel prices,
and capacity additions.
DEMAND. The Northwest peak demand is forecasted to grow at an average
annual growth rate of approximately 1% from 2000 through 2029.
FUEL PRICES. Forecasts for natural gas and oil use a consensus fuel price
forecast derived from published fuel price forecasts. Table S-1 summarizes the
fuel price forecasts used in the Base Case.
CAPACITY ADDITIONS. Based on assessments of the status of announced
plants, PHB Hagler Bailly has estimated operational capacity additions of 1,756
MW of natural gas-fired combustion turbines and combined cycle units in the
Northwest through 2002. Thereafter, capacity additions are based on the results
of modeling and simulation of developer's decisions.
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TABLE S-1
DELIVERED FUEL PRICES (2000$/MMBTU)
FUEL REGION 2000 2005 2010 2015 2020 2025
- ---- ---------- ----- ----- ----- ----- ----- -----
Natural Gas Montana 2.46 2.29 2.48 2.55 2.62 2.68
Oregon 2.46 2.31 2.45 2.53 2.59 2.66
Washington 2.61 2.46 2.60 2.69 2.75 2.82
Fuel Oil No. 2 Montana 5.93 5.26 5.35 5.57 5.75 5.94
Oregon 5.61 4.92 5.01 5.23 5.42 5.62
Washington 5.96 5.23 5.33 5.56 5.76 5.97
Fuel Oil No. 6 Montana 3.66 3.30 3.35 3.46 3.56 3.67
Oregon 2.91 2.54 2.59 2.71 2.81 2.91
Washington 3.10 2.70 2.76 2.88 2.99 3.10
S.5 RESULTS AND CONCLUSIONS
Market price forecasts are presented for three pricing regions: Montana,
the physical location of the assets; Washington Oregon East, representative of
the Mid-Columbia spot market; and Washington Oregon West, a major contractual
point of delivery for power generated by the other owners of the Colstrip
generating units. In addition to directly marketing the output of the portfolio
of assets in Montana, PPL Montana has the ability to sell and deliver power to
out-of-state counterparties under open access transmission tariffs with
transmission providers such as the Montana Power Company. PPL Montana also has a
contingent agreement to purchase an interest in the Colstrip Transmission System
from the Montana Power Company. Should PPL Montana purchase an interest in the
Colstrip Transmission System, they expect to market approximately 210 MW of
Colstrip capacity directly to Mid-Columbia counterparties at the Garrison, MT
substation and avoid paying the Montana Power Company open access transmission
tariff.
The energy price forecast presents the marginal cost of generating
electricity in these electricity markets. The additional compensation for
capacity needed to maintain a minimum amount of capacity in the market is
factored into the all-in market price forecast. Thus, the all-in price is a good
representation of the average price needed in the marketplace to maintain
equilibrium. It should be noted that the amount of compensation for capacity
needed in the market is directly related to the energy price level and the
ability of the marginal unit to recover its fixed costs. As energy prices rise
and fall, compensation for capacity will also adjust to ensure that the total
going-forward costs of the marginal unit are met. As a result of this dynamic
equilibrium, the revenues, which form the all-in market price, should be
sufficient to support the minimum amount of capacity needed by the system.
Using the assumptions presented in Chapter 4, PHB Hagler Bailly developed a
"Base Case." It should be recognized that this Base Case will vary to the extent
the input assumptions change, and such assumptions should be reviewed with the
same rigor as the resulting forecast. In addition to the Base Case, PHB Hagler
Bailly developed two sensitivities as outlined below:
- "Low Fuel Price Case," which tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu
reduction in the 2000 gas and oil prices (which is carried throughout the
study period).
- "High Hydro Case" which reflects the result of five straight high hydro
seasons (2000 - 2004) in the WSCC. The high water data is based on the
average of the two highest years in the past ten years. After the initial
five years, the case reverts back to the Base Case (based on the average
hydro flows over the last ten years).
Since fuel oil and natural gas are the marginal fuels in several of the
transmission pricing areas, the energy price forecast is driven in large part by
the forecasted price of these fuels. In order to test the sensitivity of the
Base Case energy price forecast to changes in the natural gas and oil forecasts,
we developed the Low Fuel Price Case. The Low Fuel Price Case represents a
reduction of approximately 20% in the fuel price. We believe that this
represents a good example of the fuel price fluctuations (downward) based on
historical
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213
information (1996-2000). Also, because the region is dependent on hydro
generation, we developed a High Hydro Case to represent the potential impact of
five consecutive high hydro generation years with an increase in annual hydro
generation of approximately 18% over the average annual hydro generation assumed
in the Base Case. These sensitivities have been developed to portray the impact
of changes in critical assumptions, and do not necessarily present a "worst"
case scenario.
The all-in market price combines the energy price with the price received
by generators for other relevant generation services and energy products in the
market. The "all-in" price reflects PHB Hagler Bailly's estimate of the total
market price that generators will recover. The all-in price results of the study
are summarized in Figures S-1, S-2, and S-3.
As illustrated below, the prices decline in the early years of the study
period as new generation is added to the WSCC in the analysis. After the initial
decline, the All-In prices in Washington Oregon East and Washington Oregon West
are relatively flat. The Montana prices increase during the study period to
approximately the same level as Washington Oregon West. Since the Montana
pricing area is a net exporter of energy, the prices reflect Montana's ability
to market its lower cost resources to higher priced regions.
The reduction in oil and gas prices in the Low Fuel Price Case results in a
corresponding reduction in market prices for the study period. The initial
decrease is approximately 8%. The decrease is approximately 14% from 2003
through the end of the study reflecting the increase of gas units on the margin.
The increase in hydroelectric generation in the initial years of the High
Hydro Case depresses prices lower than the Low Fuel Price Case. The decrease is
approximately 5% to 12% in the first five years. The reduction in prices pushes
out the entry of the first generic new generation in the Northwest until 2005.
After 2005, the prices are approximately the same as the Base Case.
FIGURE S-1
MONTANA ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[MONTANA ESTIMATED ALL-IN PRICE FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE ITER21D
---------- -------- -----------------
2000 24.1000 24.6900 26.6600
23.9000 24.6600 26.5000
2002 23.3000 24.2400 26.6300
24.6000 22.3000 26.0200
2004 24.4000 23.9800 26.9300
25.0000 21.4100 25.0200
2006 24.6000 21.4100 24.7400
24.8000 21.6400 24.8400
2008 25.2000 21.9000 25.4100
25.4000 22.1600 25.4800
2010 25.8000 22.3500 25.7100
25.3000 21.8600 25.2800
2012 25.5000 22.0900 25.5600
25.8000 22.4000 26.0600
2014 26.3000 22.6600 26.4100
25.9000 22.4500 25.9900
2016 25.7000 22.3700 25.7500
26.0000 22.4400 26.0100
2018 26.0000 22.4000 25.9600
26.4000 22.6915 26.3672
2020 26.3000 22.6949 26.3726
26.4000 22.6916 26.4144
2022 26.8000 23.0875 26.8339
27.0000 23.1586 26.9663
2024 27.1000 23.2425 27.1058
27.2000 23.2721 27.1555
2026 27.6000 23.6930 27.6342
27.7000 23.7000 27.6632
2028 27.8000 23.8996 27.8604
28.3000 24.2406 28.3290
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FIGURE S-2
WASHINGTON OREGON EAST ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[WASHINGTON OREGON EAST FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE
---------- -------- ---------
2000 26.7000 27.1000 29.3300
26.3000 26.8400 28.8800
2002 25.3000 25.9600 28.5300
26.6000 24.1000 27.9800
2004 26.3000 25.5600 28.7000
27.1000 23.3500 27.1400
2006 26.5000 23.1900 26.6400
26.5000 23.2000 26.5200
2008 26.7000 23.3300 26.9200
26.7000 23.3500 26.7600
2010 26.9000 23.4200 26.8700
27.0000 23.4700 26.9800
2012 27.0000 23.4900 27.0200
27.0000 23.6300 27.3200
2014 27.6000 23.8700 27.7000
27.1000 23.6600 27.2600
2016 27.1000 23.6500 27.1100
27.1000 23.5200 27.1100
2018 27.1000 23.4800 27.0800
27.2000 23.5315 27.2072
2020 27.2000 23.5049 27.1826
27.2000 23.4916 27.1744
2022 27.2000 23.5375 27.2239
27.2000 23.4586 27.1763
2024 27.2000 23.4725 27.1858
27.2000 23.4721 27.2155
2026 27.3000 23.5530 27.3242
27.3000 23.5100 27.2932
2028 27.4000 23.6896 27.5104
27.5000 23.6706 27.5290
FIGURE S-3
WASHINGTON OREGON WEST ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[WASHINGTON OREGON WEST FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE
---------- -------- ---------
2000 27.1000 27.5700 29.8600
26.7000 27.3000 29.4000
2002 25.7000 26.4100 29.0400
27.0000 24.5600 28.5200
2004 26.7000 26.0200 29.2400
27.7000 23.8000 27.6600
2006 27.1000 23.6200 27.1500
27.0000 23.6400 27.0900
2008 27.2000 23.7700 27.4200
27.2000 23.7600 27.2000
2010 27.4000 23.8300 27.3300
27.4000 23.8800 27.4300
2012 27.4000 23.9000 27.4700
27.5000 24.0400 27.7600
2014 28.0000 24.2700 28.1400
27.6000 24.0600 27.7100
2016 27.5000 24.0400 27.5400
27.5000 23.8900 27.5000
2018 27.5000 23.8300 27.4400
27.5000 23.8215 27.4972
2020 27.5000 23.8049 27.4826
27.5000 23.8116 27.5144
2022 27.5000 23.8475 27.5439
27.5000 23.7786 27.5163
2024 27.5000 23.7725 27.4858
27.6000 23.7921 27.5655
2026 27.5000 23.7830 27.5442
27.5000 23.7700 27.5432
2028 27.7000 23.9596 27.7804
27.7000 23.9406 27.7990
S-5
215
CHAPTER 1
INTRODUCTION
1.1 OBJECTIVE
PHB Hagler Bailly, Inc. (PHB Hagler Bailly) was retained by Chase
Securities Inc. (Chase Securities) to independently assess future prices for
electric energy and related products in the Western Systems Coordinating
Council -- Northwest market in support of a financing of PPL Montana's
acquisition of generating assets from Montana Power Company.
1.2 ASSET DESCRIPTION
The portfolio of assets includes coal-fired generation and hydro
generation. The coal-fired generation includes the 154 MW (net) Corette power
plant and PPL Montana's share of Colstrip Units 1 through 3 (529 MW net). The
hydro generation consists of 577 MW (net) of run-of-river hydro generation.
1.3 STRUCTURE OF THE REPORT
This document describes the existing and anticipated electricity market
structures in the Northwest, our approach to constructing forward-price
forecasts for generation services, and the specific assumptions applied for this
market assessment. The market framework and assumptions outlined in the document
are then used to derive a market price forecast for a Base Case analysis and
various sensitivities. The report is organized as follows:
- Chapter 2 describes the evolving structure of the markets in WSCC.
- Chapter 3 presents our approach to developing forward-price forecasts for
generation services.
- Chapter 4 discusses the development of assumptions and data to describe
the WSCC-Northwest marketplace.
- Chapter 5 presents the market price forecasts for the Base Case and two
alternative (or sensitivity) cases.
- Appendix A supplements the fuel forecast presentation in Chapter 4 with
further details concerning regional coal pricing trends.
- Appendix B identifies the transmission transfer capability between WSCC
regions.
- Appendix C outlines the amount and timing of new plant additions assumed
in the analysis.
- Appendix D illustrates the projected position of the target assets in the
regional market supply curve.
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216
CHAPTER 2
MARKET STRUCTURES IN THE WSCC
2.1 INTRODUCTION
The Western Systems Coordinating Council (WSCC) consists of 78 member power
systems and 21 affiliates in 14 states. These states include Arizona,
California, Colorado, Idaho, Nevada, Oregon, Utah, Washington, Wyoming, parts of
Montana, Nebraska, New Mexico, South Dakota, Texas, part of northwestern Mexico,
and Alberta and British Columbia, Canada. Currently the only centrally organized
wholesale competitive power market in the WSCC-U.S. is in California. The
generator services market for the remaining portion of the region is primarily
based on bilateral wholesale contracts.
The WSCC consists of approximately 59 million electricity consumers with
more than 700,000 GWh of annual consumption. Over 40% of the installed capacity
in the region is hydro generation. Oil-fired and gas-fired generation represent
almost 30% of the installed capacity. Over 20% of the installed capacity is
coal-fired generation. A relatively small portion of the capacity, approximately
6%, is nuclear generation. The annual energy demand in the WSCC is projected to
grow at approximately 1.5%.
One of the key factors that affects prices is the structure and
institutions of the market. This chapter describes the structure of the
generator services market in the WSCC, focusing on two major markets: the
Northwest and California. The Northwest, consisting of Montana, Washington,
Oregon, and Idaho, represents the primary market for power from the acquired
facilities. California represents a secondary market, and one that has undergone
substantial restructuring in the last year. Both of these markets may evolve
over time to a structure that differs from those described here.
2.2 COMPETITIVE POWER MARKETS
Much of the recent progress toward implementing competition in electricity
markets is due to a series of legislative and regulatory decisions rendered over
the past two decades. The legislative and regulatory framework behind the
development of competitive wholesale electricity markets in the United States
can be largely traced to the 1978 Public Utilities Regulatory Policies Act
(PURPA). This act spurred the growth of the non-utility generation industry and
increased wholesale competition, albeit on a limited scale due to transmission
ownership issues and other market access constraints. The 1992 Energy Policy Act
expanded wholesale competition by mandating transmission owners to provide "open
access" for all system users. Transmission access rights were further
strengthened in 1996 with Federal Energy Regulatory Commission (FERC) Open
Access Rule, Order No. 888 (Order 888). This order called for transmission
owners to offer "comparable service" to all customers through the application of
a pro forma transmission tariff.((1)) Order 888 also encouraged the creation of
ISOs, whose role in operating and managing regional transmission assets is
described in greater detail in this chapter. However, even before Order 888 was
drafted, the creation of ISOs and the establishment of formalized competitive
markets was already underway in California and the Northeast.
Compared to other countries, which have adopted a national plan for
transitioning to competitive power markets, the restructuring process in the
United States has progressed piecemeal, with significant differences between
various regions. This is largely due to the division of authority over various
aspects of the electric power industry between state and federal legislative and
regulatory bodies.
- ---------------
(1) Definition -- transmission owners must treat any of their own new wholesale
sales and purchases of energy over their transmission facilities under the
same tariffs that they apply to others. EIA, The Changing Structure of the
Electric Power Industry: Selected Issues 1998, p. 31.
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217
FIGURE 2-1
AVERAGE RETAIL ELECTRICITY PRICES
[U.S. MAP]
The debate over retail access and other measures to implement market
competition has raised a number of fundamental market transition issues. Three
of the principle issues common throughout the country are: the assessment and
allocation of stranded costs, the elimination of market power and the method for
guaranteeing fair and impartial access to the transmission system. These issues
are briefly discussed below.
Stranded costs can be defined as the positive excess of the net book value
of generation assets and power purchase costs over the market value of the
assets. The introduction of competition in formerly regulated electricity
markets presents a significant financial burden for utilities with generating
assets or power purchase contracts, which may now be priced out of the market. A
large number of utilities throughout the United States are faced with losses due
to the adoption of market pricing before they have had a chance to recover the
cost of their prior investments through their rate base. In order to ensure the
support of the utility industry in the restructuring agenda, many state utility
commissions and legislative bodies have agreed to allow utilities to recover
either all or part of their stranded costs through a number of different
recovery mechanisms. These recovery vehicles are designed to support the
introduction of competition while still allowing the affected utilities to
recover a specified portion of their expected losses over a fixed period of
time. However, the cost recovery method varies from state to state.
Despite two decades of Independent Power Producer (IPP) development, the
majority of the generation assets in the United States continue to be owned and
operated by vertically integrated investor-owned utilities. Within regional
electricity markets, the concentration of generating assets is often controlled
by a small number of incumbent utilities. The removal of regulation and the
introduction of market-based pricing into such markets raise concerns over the
potential abuse of market power. To relieve these concerns, federal and state
regulatory bodies have taken various measures to eliminate the threat of market
power. The principal means of dealing with market power has been the unbundling
of generation, transmission, and distribution assets. This is often followed by
the mandated sale of a certain amount of generation assets by the traditional
utilities to non-affiliated companies. Such generation auctions and negotiated
sales have resulted in the transfer of billions of dollars of generation assets
in the past few years, changing the face of the generation
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218
industry in many regions of the country. The impact of current and future
unbundling and generation ownership transfers must be considered when analyzing
long-term conditions in regional power markets.
In addition to the recovery of stranded costs and elimination of market
power, the ability to reach newly opened markets through the high voltage
transmission grid at a fair price is a fundamental requirement for introducing
true competition. Thus, the issue of transmission access is at the core of the
restructuring movement.
2.2.1 RELIABILITY AND COMPETITIVE MARKETS
Much of the development of competitive market structures and system
operations in recent years has involved the balancing of system reliability
concerns with the desire to allow the market to drive the development of the
electricity industry. This balancing of market forces and reliability concerns
is evident in the transmission industry. The high-voltage transmission system
and corresponding bulk power markets in the United States were originally
developed to ensure reliability of supply rather than to support commercial
transactions and power trading. Stemming from the Northeast blackout of 1965,
the utility industry organized regional reliability councils to coordinate
reliability practices in the United States and parts of Canada and Mexico. The
continental United States is divided into 10 regional reliability councils whose
policies are, in turn, coordinated by the North American Electric Reliability
Council (NERC). The reliability councils are voluntary organizations that
establish guidelines for all member utilities and suppliers. Two of the
principle guidelines established by each council concern:
- MINIMUM OPERATING RESERVES. Operating reserves represent generating
units that are maintained in a spinning or fast-start condition so that
they can rapidly respond to an outage at another unit or some other
emergency condition.
- MAXIMUM AREA CONTROL ERROR. Area control error is a measure of the
difference between actual and scheduled power flows. It is controlled to
maintain the standard operating frequency of the alternating current
power supply system and to prevent damage to generators and other
equipment connected to the grid.
The ten regional reliability councils are part of larger interconnected and
synchronized electric power systems. There are three synchronized electricity
networks in the United States:
- The Eastern Interconnection [ECAR, MAAC, MAIN, MAPP, NPCC (excluding
Quebec), SERC, SPP, and FRCC]
- The Western Interconnection (WSCC)
- Electric Reliability Council of Texas Interconnection (ERCOT).
These systems are interconnected through limited D-C ties, but their A-C
systems operate independently of one another.
Power Pools
While the regional reliability councils provide standards and guidelines,
they do not provide actual electricity dispatch, scheduling or other
transmission system operational services. In order to capture the economies of
scale associated with load and resource pooling as well as joint-dispatch and
transmission operations, utilities in a number of regions voluntarily
established power pools, the first of which, the PJM, was established in 1927.
Power pools attempt to capture the benefits associated with being part of a
larger generation and transmission system, including improved reliability
through coordinated maintenance planning and shared operating reserves, as well
as the blending of load profiles and generating resources. Power pools vary
widely throughout the United States in terms of the degree to which they provide
coordination and services.
While pooling arrangements were beneficial for reliability, it is possible
that they are not suitable for supporting and developing truly competitive
electricity markets. Due to their limited membership and strict
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membership criteria, external marketers, power producers, and eventually
regulatory bodies viewed power pools as barriers to competition. Through Order
888, FERC is actively encouraging the formation of ISOs that replace the power
pool organization in scheduling, dispatching and operating the regional
transmission system. The purpose of the ISO is to provide independent grid
management through a process in which all system users are treated equally. Many
of the utilities in the most tightly coordinated power pools in the United
States were among the first to file ISO applications with the FERC, but the ISO
trend is now progressing through the industry as an increasing number of states
enact legislation implementing retail access.
Independent System Operators
The creation of an ISO entails the transfer of management and operational
control of the transmission system to an independent administrator that has no
financial interest in the operation of the generating facilities using that
network. As interstate transmission organizations, new ISOs will fall under the
regulatory jurisdiction of FERC and must seek FERC approval for their
operations. The motivation for establishing ISOs is strong, since a retail
provider affiliated with an investor-owned utility which has not satisfied the
FERC ISO criteria cannot compete for customers outside its franchised service
territory unless it maintains rates based on cost of service.
In connection with the approval process, FERC has created a list of
criteria to which ISOs must adhere. Two of the fundamental criteria of the
proposed ISO framework are the need to establish an independent governance
structure for the ISO and the application of a postage-stamp tariff for the
entire ISO region which would eliminate the payment of a transmission fee to
each control area that is involved in a transaction ("pancaking"). Independent
governance of each ISO is critical to the ability of such ISO to execute
transactions in an unbiased manner, applying the same service standards and
prices to both incumbent utilities and new market entrants. The application of a
system-wide tariff is also critical for competition. It establishes a level
playing field in terms of transportation costs for all generators within an
ISO's territory, and it reduces the "pancaking" effect of wheeling power through
such ISO's territory.
The role of the ISO in a functioning spot market is critical to the
efficient operation of competitive markets. The spot market may be either
operated by the ISO or by a separate Market Operator (or Power Exchange). The
spot market is designed to provide a balancing function in which excess
generation capacity is matched to demand not already covered under existing
bilateral contracts. This balancing market allows wholesale suppliers and
customers to hedge their existing bilateral contracts with purchases from the
spot market, while also providing the ISO with a source for regulating capacity
and emergency supply through various market mechanisms. The specific
characteristics of the regional ISO and power markets will have a direct
financial and operational impact on the affected generating assets.
Several ISOs are already operating or under review by FERC, while several
others are in the development stage. However, only a few of these ISOs currently
incorporate a spot market function. There are currently five functioning ISOs in
the United States: the California ISO (CA-ISO), the PJM-ISO, the New England ISO
(NE-ISO), the ERCOT-ISO((2)), and the New York ISO (which officially assumed
control of the New York Power Pool grid on November 18, 1999). The Midwest ISO
(MISO) was also conditionally approved by FERC in September 1998 and is expected
to begin operations in 2001. The Alliance RTO filed for FERC approval in June
1999. In addition, the Entergy Corporation has proposed the creation of a for-
profit transmission subsidiary (Transco), to operate and manage its transmission
assets in a manner similar to an ISO.
In Order No. 2000, FERC requested that transmission owners join regional
transmission organizations (RTOs) on a voluntary basis to boost competition. The
rule requires that all public utilities that own, operate, or control interstate
transmission file by October 15, 2000 a proposal for an RTO. The four
characteristics of an RTO are: independence, scope and regional configuration,
operational authority, and short-term reliability. Based on this, several
transmission owning companies are working together to form RTOs in WSCC. The
proposed Northwest RTO is discussed further below.
- ---------------
(2) ERCOT is not under FERC jurisdiction; the Texas Public Utility Commission
approved the ISO proposal.
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220
While each of the individual power pools are developing individually and
have different products, the final resulting economies will likely be similar;
thus, PHB Hagler Bailly approaches all regions with the same fundamental
analysis (see Chapter 3).
2.3 NORTHWEST MARKET
2.3.1 OVERVIEW
The Northwest generator services market is primarily based on bilateral
contracts. However the market also includes two informal spot markets with
survey data reported daily (California-Oregon Border [COB] and Mid-Columbia), a
formal short-term/spot market (APX/Chelan Mid-Columbia), and a formal futures
market (the NYMEX COB futures market). There are currently no markets for
ancillary services, other than bilateral contracts. Utilities in the Northwest
are members of the Northwest Power Pool (NWPP), a voluntary reserve group.
Retail customer direct access is limited in the region. Because of the mild
climate, the region is strongly winter peaking. The market is unique in the
United States in its reliance on hydropower. Almost 70% of the installed
capacity in the region is hydro generation that represents approximately 60% of
the annual energy generation in the region (based on the average of the last 10
years of hydro generation). Coal-fired generation is the second largest
component representing approximately 18% of the installed capacity and 26% of
the annual energy generation. There is a relatively small amount of nuclear
generation in the region, approximately 2% to 3% of installed capacity and
annual generation. Natural gas and oil comprise approximately 8% to 9% of the
installed capacity and annual generation. The market is also characterized by
the dominance of one transmission owner, the Bonneville Power Administration
(BPA).
2.3.2 THE NORTHWEST POWER POOL
The purpose of the NWPP is to promote cooperation among its members in
order to:
- achieve reliable operation of the electric power system
- coordinate power system planning
- assist in planning of transmission within the Northwest Interconnected
Area.
NWPP calculates operating reserve requirements for the pool, which members
comply with on a voluntary basis. The pooling of requirements allows members to
carry less reserves and still meet WSCC minimum criteria. NWPP is a "loose"
pool, in that it does not conduct any central dispatch.
WSCC is the first regional electric reliability council in North America to
implement a voluntary reliability management program to preserve reliability
with sanctions for non-compliance with established reliability criteria. As of
March 2000, 28 WSCC members, which represent over 82% of the customer load in
WSCC, have signed WSCC Reliability Management Service agreements.
2.3.3 RETAIL CUSTOMER DIRECT ACCESS
Because of the relatively low electricity prices in the Northwest, interest
in retail customer direct access has been progressing slower than in California
and in the Northeast. In Montana, retail customer direct access will be
available for all power company customers by mid-2002. Montana Power Company has
already implemented customer choice.
In Oregon, Portland General Electric and Pacificorp must provide open
access to industrial customers beginning in October 2001. The benefits of
offering open access to residential customers in Oregon is still being reviewed.
By October 2001, residential customers of Portland General Electric and
Pacificorp must be offered a portfolio of power options (i.e., market-based
rates or green power rates). Competition is allowed in Washington, but it is not
mandated. There is currently no set time frame for implementing a comprehensive
restructuring plan in Washington.
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2.3.4 SIGNIFICANCE OF HYDROPOWER
The large amounts of hydropower in the Northwest create a market for
generator services that is significantly different than in other parts of the
country. Prices and system reliability are largely driven by the amount of water
available, representing increased relative risk to generators. During the spring
and early summer, during peak runoff, on-peak prices of $10/MWh or less are not
uncommon. Prices are highest in the winter, when regional demand is highest and
water supply is lowest, and in late summer, when California demand is highest.
The chief constraint on power supply in the region has historically not
been capacity, but available energy. Sustained peaking requirements can deplete
water supplies. The sustained peaking capacity, defined as the maximum capacity
that can be delivered during a continuous heavy-load 10 hour period for the 5
work days, of the Federal hydropower system (U.S. Army Corps of Engineer and
Bureau of Reclamation dams) can be 50% or less of nameplate capacity.
Concerns about dwindling populations of anadromous fish (steelhead and
salmon) are increasingly constraining the generation of electricity from dams.
Dam construction has blocked salmon and steelhead passage to many of their
natural habitats along the Columbia River. The National Marine Fisheries
Service's "Biological Opinion on Columbia River System Operations," released
March 1995, significantly affected the operation of hydroelectric facilities on
the Columbia and Snake rivers. The most significant change in operations was
that generators were constrained from generating as much to meet the normal
winter peaks, to allow sufficient water to be available in time for spring
downstream migrations of salmon and steelhead smolts. Hydro-generation is also
occasionally required, in spite of unavailability of open access to the
transmission system, to reduce nitrogen levels that would be otherwise created
by spilling water.
2.3.5 BONNEVILLE POWER ADMINISTRATION
BPA markets power from the federal dams and one nuclear plant in the
Columbia River Basin. It supplies about 40% of the Northwest's electricity. Its
customers include public utilities, local governments, irrigation districts,
investor-owned utilities, certain large industries, and power marketers and
brokers. BPA also owns more than half of the high-voltage transmission system in
the Northwest, and 80% of the 500 kV portion of the system. Because of this
large ownership share, there are concerns about BPA's ability to use its
transmission system to give unfair advantage to its power business in the
competitive wholesale electricity market.
To address these concerns, the Northwest Energy Review Transition Board,
representing the four Northwest governors, studied proposals for FERC regulation
of BPA transmission, and also stranded cost recovery mechanisms. This Board was
set up as an outcome of a year long Comprehensive Review of the Northwest Energy
System convened in 1996. The Comprehensive Review was initiated in response to
the electricity industry restructuring, with the intent to allow the Northwest
to shape its own destiny during this process.
BPA has undertaken certain changes in response to the concerns about
transmission control. It has voluntarily complied with the FERC's open access
directives. It has also functionally separated generation and transmission.
Further changes are expected, however. One of the key issues is whether and how
BPA's transmission system should be regulated by FERC under the Federal Power
Act (FPA). Conformance with the FPA is likely to create cost shifts in
transmission charges, possibly increasing transmission rates substantially for
some customers, while reducing them for others. Currently, for example, a
separate transmission rate is charged for use of the DC intertie to Southern
California. A move to uniform transmission rates would likely decrease costs for
customers using this line, and increase costs for most other customers.
Another key issue related to FERC jurisdiction over BPA is treatment of
BPA's "organic" statutes, which include the Bonneville Project Act of 1937, the
Flood Control Act of 1944, the Regional Preference Act of 1964, the Federal
Columbia River Transmission System Act of 1974, the Northwest Power Act of 1980,
and others. The Transition Board recommended that applicable provisions of the
FPA supersede conflicting sections of the organic statutes.
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2.3.6 DEVELOPMENT OF REGIONAL TRANSMISSION ORGANIZATIONS
In response to FERC Order No. 2000 several northwestern electric
transmission companies have begun to work together to form a regional
transmission organization. The following companies are working together to form
the Northwest Regional Transmission Organization:
- Avista
- Bonneville Power Administration
- Idaho Power Company
- Montana Power Company
- Nevada Power Company
- Pacificorp
- Portland General Electric Company
- Puget Sound Energy, Inc.
- Sierra Pacific Power Company.
The Northwest RTO is proposed to be a single entity that has the
characteristics and functions as set forth in Order 2000 and other applicable
FERC orders. Some of the basic principles of the Northwest RTO include the
following:
- Provide transmission reliability
- Facilitate and promote open bulk power/wholesale markets
- Provide economic incentives for the reliable and efficient operation and
maintenance of transmission facilities
- Preserve obligations of the United States to the Tribes associated with
the Federal Columbia River Transmission System and to Canadian entities
under the Columbia River Treaty.
The Northwest RTO will not include a power exchange. The companies are in
the early stages of developing the Northwest RTO and plan to file the plan by
the October 15, 2000 deadline.
2.4 CALIFORNIA
On September 23, 1996, the California General Assembly enacted Assembly
Bill 1890 (AB 1890) in an effort to restructure the electric utility industry
and stimulate wholesale and retail competition in California. This legislation
has allowed retail customers to choose their generation supplier since March 31,
1998. In addition, under AB 1890, small commercial and residential customers
received a 10% rate reduction on January 1, 1998, and a rate freeze until 2002.
AB 1890 also created two new wholesale market structures to operate and manage
the new competitive market: the CA-ISO and the California Power Exchange
(Cal-PX).
The role of the CA-ISO is to coordinate and ensure impartial access to the
state's high voltage transmission system, 75% of which is under CA-ISO
management. Investor-owned utilities were required to transfer operation and
management of their transmission facilities to the CA-ISO. In return for
transferring control over their transmission assets, these utilities are allowed
to collect stranded costs for a period of up to five years through a Competitive
Transition Charge (CTC). The CTC is included in the retail distribution rates
within the utilities' respective service territories. In addition to the
transfer of control over transmission, the major investor-owned utilities were
required to divest 50% of their fossil fuel generation assets.((3)) This
divestiture was seen as a critical element in reducing the regional market
dominance of the incumbent utilities.
- ---------------
(3) The mandate initially did not cover nuclear, hydro or geothermal generation.
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The Cal-PX is a non-profit corporation whose primary purpose is to provide
an efficient, competitive energy auction that meets the loads of Cal-PX
customers at market prices. Pacific Gas & Electric (PG&E), Southern California
Edison (SoCal Edison), and San Diego Gas & Electric (SDG&E) are required by AB
1890 to buy and sell electricity through the Cal-PX until March 31, 2002.
Together, these three investor-owned utilities represent approximately 80% of
the electricity used in California. The Cal-PX re-prices regional markets based
on congestion and coordinates supplemental energy bids, which are used by the
CA-ISO to match loads and resources on a real-time basis. The structure of the
market and role of the CA-ISO and Cal-PX are explained in greater detail below.
2.4.1 MARKET STRUCTURE IN CALIFORNIA
This section describes the market structures for energy and ancillary
services in California as they currently exist or will exist in the foreseeable
future. Unlike the former tight pools of the Eastern United States, California
does not have a separate market for installed capacity.
Electric Energy Market
The California electric energy market currently consists of four markets
that are interrelated and operate in chronological order:
- block forwards market
- day-ahead market
- day-of market
- real-time market.
The block forwards, day-ahead, and day-of markets are considered forward
markets, in that the settlement prices and quantities are determined before the
physical transactions occur. Today the Cal-PX is the primary entity supporting
these forward markets, but, in the future, other competing organizations may
support similar markets.((4)) The real-time market is a true ex post facto
(after the fact) market that is settled after delivery at the prices and
quantities in effect at the time of delivery. This market is supported by the
CA-ISO. The three energy sub-markets are also regionally subdivided and have
different hourly prices when transmission flows are constrained, as discussed
below.
In contrast with the market designs in the New England Power Pool (NEPOOL),
PJM, New York, England-Wales, and certain other electricity markets, the
California electricity market does not explicitly pay for generating
capacity.((5)) A generator must recover its fixed costs by selling ancillary
services and by selling energy in those hours when the market price exceeds the
generator's fuel and other variable operating costs. In order for peaking and
cycling plants to fully recover their costs, they will most likely have to
submit offer prices that exceed their variable costs in those hours when
capacity is tight and they are reasonably assured of being dispatched. In
addition, ancillary services and Reliability Must-Run (RMR) contracts are other
sources of revenue that may offset their fixed costs.
BLOCK FORWARDS MARKET. The block forwards market trades a standardized
contract for physical month on-peak energy. The contract is for a certain size
(1 to 25 MW) for the on-peak period (6 a.m. to 10 p.m. Monday through Saturday,
excluding certain holidays) and to a specific delivery point (NP-15 or SP-15).
- ---------------
(4) A competing market actually exists now. The Automated Power Exchange (APX)
currently brokers hourly trades in electric energy and ancillary services
for delivery in California up to one week ahead. The reason for the
dominance of the Cal-PX as the forward market is that California's
investor-owned electric distribution companies are required to buy and sell
exclusively through the Cal-PX through the end of the transition period
(March 31, 2002).
(5) Other "energy-only" markets include Australia and New Zealand.
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DAY-AHEAD MARKET. The day-ahead market allows a market participant to
commit to energy purchases or sales at prices that are more predictable and less
volatile than the day-of and the real-time markets. Most of the energy purchased
and sold in California is exchanged through the day-ahead market.
DAY-OF MARKET. The day-of market was formerly configured as the
"hour-ahead market." It allows participants the opportunity to adjust their
scheduled production or consumption to reduce anticipated real-time deviations
from their final day-ahead schedules. This market settles on the quantity
deviations from each participant's final day-ahead schedule.
For the day-of market, Cal-PX runs three auctions for hourly on-peak and
off-peak energy delivery each day, rather than the 24 hourly auctions conducted
in the previous hour-ahead trading. Traders will still be able to participate by
providing supply and demand bids for individual delivery hours throughout the
day.
REAL-TIME MARKET. The real-time market is an energy imbalance market run
by the CA-ISO. If a generator delivers less (more) energy than the combined
total it scheduled in the day-ahead and day-of markets for a given hour, it is
deemed to have purchased (sold) the deficit (surplus) in the real-time market.
Similarly, a customer that takes more (less) than it scheduled is deemed to have
purchased (sold) the surplus (deficit) in the real-time market.
The CA-ISO determines the real-time market prices based on the dispatch
from the merit order stack consisting of all supplemental energy bids and
ancillary services energy bids. Generators must submit supplemental bids after
the close of the day-of market but at least 30 minutes before the hour of
operation commences. Participants in the Cal-PX submit their bids to the Cal-PX,
which then passes the bids on to the CA-ISO. Other scheduling coordinators
perform the same role for their respective generation assets. Those participants
that clear the market are notified and are expected to operate in accordance
with their bid.
Ancillary Services Markets
In California, the CA-ISO operates competitive markets for procuring the
following four ancillary services:
- regulation
- spinning reserve
- non-spinning reserve
- replacement reserve.
Generators and interruptible loads participating in the Cal-PX submit bids
to sell any of the regulation or reserve services to the Cal-PX. The Cal-PX
forwards this information to the CA-ISO without modification. The CA-ISO then
procures regulation and reserves through four separate auctions that are held
sequentially. These auctions are interdependent because the same resource can
often provide more than one type of ancillary service. The most stringent
performance standard is imposed on regulation; consequently the auction for this
service is held first. The auctions for spinning reserve, then for non-spinning
reserve, and finally for replacement reserve follow the regulation auction
sequentially.
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CHAPTER 3
APPROACH TO MARKET PRICE FORECASTING
3.1 INTRODUCTION
This chapter discusses PHB Hagler Bailly's approach to forecasting market
prices for the services of generating units. The first section discusses the
issues faced while forming these forecasts, namely the distinction between
capacity and energy markets and the evolution of market structures. The second
section describes the relationship between energy markets and compensation for
capacity, and the implications for forecasting market prices. The third section
summarizes the methodology used for estimating market prices for electricity in
this analysis.
3.2 ISSUES IN FORECASTING MARKET PRICES
This section discusses several foundational issues that frame how PHB
Hagler Bailly approaches market price forecasting. The first of these issues is
the concept of economic equilibrium and how it suggests that the market will
react to returns on equity (or lack thereof). The second has to do with the
components of revenue that are present in our forecasts. Each of these topics is
addressed below.
3.2.1 ECONOMIC EQUILIBRIUM AND MARKET PRICE FORECASTING
A fundamental tenant of PHB Hagler Bailly's market price forecasting
approach is that markets are attempting to adjust to economic equilibrium
conditions. By economic equilibrium, we mean that the market will attempt to
exploit or capture excess margins through entry (e.g., when the return on equity
is above market), and will attempt to increase margins where they are below
market through exit. In other words, excess returns should not persist because
someone will enter to capture a portion of the above market return.
While the concept of economic equilibrium is sound in principle, actual
markets may not follow economic equilibrium exactly. Many industries have shown
cycling returns, where high returns are followed by excess entry resulting in
low returns which are followed by a disincentive to invest which results in high
returns. While such cycling and overshooting is often a characteristic of
commodity markets, these markets are, in general, attempting to adjust to a
level commensurate with economic equilibrium -- that is, they cycle around the
price level suggested by economic equilibrium.
3.2.2 CAPACITY AND ENERGY MARKETS
One must consider the institutions that define the electric market in order
to make market price forecasting relevant. Some electric markets, such as those
in the Northeastern United States (NYPP, PJM, NEPOOL) and England and Wales,
provide separate compensation for energy and capacity. Generators have the
opportunity to recover their variable costs and going-forward costs((1)) from
the energy market and in the capacity market. This market structure encourages
generating capacity and provides for fair market compensation.
Other electric markets, such as Australia, New Zealand and many regions of
the United States, are energy only markets where the market does not separately
pay generators for their installed capacity.((2)) In theory, an energy only
market leads to economically efficient capacity levels in the long run. As long
as prices rise sufficiently to allow the generators in the market to recover
their variable costs and going-forward costs,
- ---------------
(1) Going-forward costs are those costs that a generator cannot avoid if they
remain in the market, such as fixed operation and maintenance (O&M),
property taxes, employee benefits, and incremental capital expenditures.
These costs do not include a return on capital or debt service, as these
costs are deferrable on capital that is already committed to the marketplace
(e.g., sunk).
(2) Forms of energy-only pricing systems also may include payments for spinning
and operating reserves. However, payments for ancillary services are
differentiated from capacity reserve payments for purposes of this
discussion.
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the average energy price should cover the costs of new capacity, even if
there is not a separate capacity payment delivered either from a traded capacity
market or administered by the market operator.
While the type of market in place in a given region will determine the
composition of the revenue streams and will affect the mix and timing of new
generating units, the financial return on new assets is likely to be similar in
both types of markets as generators seek to cover their total going-forward
costs.
The structure of U.S. electric markets is evolving and new forms of market
organization have been adopted in areas such as California and the Northeast and
are proposed for the Midwest and ERCOT. These structures will continue to evolve
as electric markets develop and move through the transition period from
regulated monopolies to fully functioning competitive markets. Indeed,
competitive market structures may continue to change even after a market is
considered mature, as is occurring in England and Wales.
Although no region in the United States has a fully mature market today,
there is an emerging worldwide consensus on what a competitively restructured
electricity industry should look like. Principle facets of the market should
include:
- formation of an entity to operate transmission and coordinate schedules
that is independent of any generation owner or market participant, either
through an ISO or a TRANSCO
- some form of "congestion or locational pricing" (either zonal or nodal)
to deal with transmission congestion in a market-based fashion
- formation of a power exchange with, at a minimum, an hourly spot market.
In addition, a competitive market should allow for effective competition
among generators, with minimal abuse of market power.((3))
Relationship between Energy Markets and Compensation for Capacity
The United States is currently experimenting with both markets that have
fixed reserve margin requirements coupled with capacity markets and those that
implicitly price capacity through high on-peak energy prices. It is not clear
which model will eventually become more widespread. Nevertheless, in both types
of markets, new generating capacity will be developed based on the revenue
streams determined through competition.
In electric markets, such as PJM, New York, or New England, where
load-serving entities are required (by administrative rule) to own or contract
for a minimum generating capacity reserve level, the capacity obligation creates
a market between those that are short on their capacity obligation and those
that have surplus capacity. In a competitive market, potential suppliers compete
to provide this capacity. Markets have been developed to support trading of this
capacity, typically in the form of daily, monthly or annual traded capacity, for
which generators are compensated for being available to produce if and when
required. In such markets, generators attempt to cover their total going-forward
costs through a combination of revenue from energy, capacity, ancillary service
markets as well as through sale of options and forwards on a bilateral basis.
In market structures without an explicit capacity market (such as
California), generators must place greater weight on recovering their
going-forward costs from the energy market. Were capacity to trade in a market
with a capacity obligation for significant amounts of revenue, one would expect
that a market without a capacity market would have more volatile prices than one
that has a capacity market.
- ---------------
(3) Ideally, the wholesale market would be competitive with no presence of
market power. However, electricity is not quite a pure commodity, as it must
be produced in real time with no inventory. This leads to the circumstance
that location matters in electricity as it does in real estate. Such a
spatial market cannot avoid the periodic presence of market power, but such
occurrences should be, ideally, minimal.
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How Are Generators Compensated for Capacity in an Energy-Only Market?
As mentioned previously, one would expect that price volatility would be
higher in a market that does not provide a meaningful stream of revenue as a
capacity payment. This is because the marginal plant (e.g., the last few
generators needed to support reliability, regardless of their efficiency) would
need to increase their bids above their costs in order to earn a sufficient
margin, when they are called upon to generate, to cover their going-forward
costs. In low load hours, however, there is an abundance of capacity present in
the marketplace, and prices are more likely to be driven to marginal cost.
Volatility in the spot market affects pricing in the forward market and for
options. Because of the volatility in spot prices, marginal generators, who
might not be expected to run but for a few hours, may be able to sell call
options for power with high strike prices. These options may, or may not,
actually be "in the money," but market participants may be willing to buy these
call options as a hedge against the possibility of even higher market prices.
These contracting mechanisms, fostered from volatile spot prices, provide
the means for some of the marginal plant to recover their going forward costs.
They also provide the mechanism for the market to secure an economic level of
reserves to meet peak demand.
Price Volatility and Capacity Markets
Even in markets with capacity obligations and a traded capacity market,
energy prices have been quite volatile. This price volatility stems from an
intrinsic characteristic of electricity: because there is no inventory,
electricity must be produced in real time. This means that errors in forecasting
demand or commitment of generating units, failures in equipment, and market
perceptions amplify price movements with the result that electricity has the
most volatile spot prices of any commodity traded.
This price volatility has exhibited itself even in markets that have a
traded capacity market. Some market participants debate whether or not a
separate capacity market is viable, useful, or relevant given that most of the
compensation earned by plants in these markets is either directly from, or
derived from, the energy market.
3.2.3 FORECASTING GENERATION SERVICE PRICES
Irrespective of where the debate on the future and viability of capacity
markets lies, PHB Hagler Bailly produces forecasts of generation service prices
by examining two components of value in our fundamental analysis:
- Energy prices reflecting the marginal cost in each hour based on a
production-cost model.
- Compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market. (This
compensation for capacity is not the same as a capacity price in a traded
capacity market.)
Compensation for capacity may take many forms. Payments could be in the
form of a capacity price arising from a capacity market, a regulated payment
fee, bilateral option contracts, payments by the ISO for ancillary services, or
in the form of energy prices above the marginal cost of the price-setting plant.
Regardless of the form, the sum of the compensation for capacity and the market
price for energy will ultimately reflect what customers are willing to pay for
both energy services and reliability. It is PHB Hagler Bailly's belief that the
majority of the compensation for capacity actually arises through energy prices
that are higher than marginal cost (and hence our energy price forecast) for
some substantial portion of hours.
Actual market price results support this belief. Figure 3-1 presents a
graph of market prices in the PJM market in February 2000. This month was
selected since it is one of the lowest load months in PJM, and prices should not
be reflecting much in the way of a "scarcity premium" associated with
insufficient generation to cover demand.
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FIGURE 3-1
PRICE VS. LOAD -- PJM WEST
[GRAPH]
What is abundantly clear is that generators do not simply bid their
marginal cost of generation under all circumstances -- were it the case that
such bidding strategies were employed, one would expect that the price results
in Figure 3-1 would be closely clustered around the line representative of
marginal cost. Rather, there is considerable dispersion in the data,
particularly in the higher load hours where marginal generation has a greater
ability to support a price above marginal cost.
The terms "compensation for capacity" and "energy price" as used in this
report reflect the prices needed by the marginal units to recover their variable
and going-forward costs. These prices together form the all-in price received by
generators to meet all of their going-forward costs. Compensation for capacity
and energy prices are inversely related; as one rises the other falls, so that
the all-in price remains somewhat in balance.
3.3 APPROACH TO MARKET PRICE FORECASTING
Projecting electric market prices (and generation product sales) requires
PHB Hagler Bailly to consider not only price formation in the market, but also
the issues of market entry and exit. Figure 3-2 provides a graphical view of PHB
Hagler Bailly's process for producing electric market price forecasts. The
process begins with a definition of the characteristics of the market, including
the electric generating units currently in operation, their production
efficiencies (including heat rate curves), a projection of plant additions
(based, in part, on announcements and, in part, on an equilibrium evaluation of
market price signals and new investments), consumer demand and load, and
generation fuel prices.
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FIGURE 3-2
APPROACH TO DEVELOPING COMPENSATION FOR CAPACITY AND ENERGY PRICES
[FLOW CHART]
Thus, this process develops prices based on a dynamic examination of market
entry and exit (including retirement) decisions made by the supply-side players
in the market. The following sections will briefly discuss PHB Hagler Bailly's
approach to each of these steps.
3.3.1 MARKET CHARACTERISTICS
The first step is to understand the nature and parameters of the market and
the generation assets that participate in that market. PHB Hagler Bailly uses a
variety of data sources to characterize the market. These include:
- PUBLISHED DATA. This data identifies the generating units, consumer
demand and load, and production capacities of existing plants.
- FUEL PRICE FORECASTS.
- PLANNED ADDITIONS. PHB identifies new additions that are assumed to be
online prior to 2003 based on a detailed review of the announced plans of
developers (tracked in the PHB Hagler Bailly IPP Database) and utilities
(contained in planning council reports). Capacity additions after 2002 are
tested in the entry and exit logic.
- RETIREMENTS OF NUCLEAR PLANTS. PHB Hagler Bailly reviews the experience
of nuclear power plant operators (tracked in the PHB Hagler Bailly
Operating Plant Experience Code Database) to identify the plants most
likely to be retired before the end of their operating licenses (and to
estimate potential retirement dates).
3.3.2 PREDICTING ENERGY PRICES AND DISPATCH
PHB Hagler Bailly uses a detailed chronological production-cost model to
simulate energy price formation in the market area of interest based on
short-run marginal costs.
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From the energy price analysis, PHB Hagler Bailly determines the net energy
margins (price minus variable cost) for each generating unit in the market.
These margins, along with estimates of "going-forward costs," are used in the
Capacity Compensation Simulation Model to predict the additional margins related
to the provision of capacity.
3.3.3 PREDICTING PRICES RELATED TO CAPACITY: THE CAPACITY COMPENSATION
SIMULATION MODEL
Compensation for capacity is a mechanism for supporting an appropriate
amount of generating capability in the system. There are two reasons for
including a measure of the compensation for capacity or shortage payment in the
projection of market prices. First, if generators bid their short-run marginal
costs into an energy market, only inframarginal plants (those not on the margin)
earn a contribution toward their going-forward costs. Plants at the top of the
supply curve receive little, if any, contributions toward their going-forward
costs. In addition, some of the baseload and cycling plants that are not at the
top of the supply curve but have high going-forward costs may not earn a
sufficient operating margin from the energy market alone to cover all of those
costs.
PHB Hagler Bailly predicts a value for compensation of capacity using PHB
Hagler Bailly's proprietary Capacity Compensation Simulation Model. This model
presumes that the market will retain a sufficient amount of capacity to meet
economic reliability targets. In other words, PHB Hagler Bailly simulates a
capacity market consisting of a supply curve and a demand curve for reliability
(or capacity) services. PHB Hagler Bailly assumes a competitive market, and that
the market-clearing compensation for capacity is determined by the intersection
of the supply and demand curves. PHB Hagler Bailly constructs supply and demand
curves for each year in the simulation time horizon.
The supply curve is developed based on all of the generators in the market.
For each generating unit, the net of going-forward costs and energy market
margins, expressed on a per-kilowatt basis, are calculated. These net costs
represent the minimum amount a generating unit needs to go forward. Ranking
these net costs in ascending order produces a supply curve for capacity.
Next, the demand curve is estimated. The demand curve is estimated by
representing the capacity associated with a target reliability level. The demand
curve is a vertical line derived using a target reserve margin or target level
of installed capacity.
Finally, the intersection of the demand curve and the supply curve
represents the capacity contribution that the market would support in that year.
The capacity contribution forecast is the capacity payment derived for each year
of the study period. A sample supply and demand curve for a hypothetical year is
shown in Figure 3-3.
3.3.4. MARKET ENTRY AND EXIT
It is necessary to assess the feasibility and timing of new capacity
additions as well as the exit of uneconomic existing capacity. PHB Hagler
Bailly's proprietary modeling approach serves two purposes:
- First, it identifies generating units that are not able to recover their
going-forward costs in the energy and capacity market and are, therefore,
at risk of abandoning the market.
- Second, it provides a rational method for ascertaining the amount,
timing, and type of capacity additions.
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FIGURE 3-3
EXAMPLE SUPPLY AND DEMAND CURVE
[SUPPLY DEMAND CURVE GRAPH]
Capacity additions through 2002 are based on known, planned additions.
Thereafter, PHB Hagler Bailly's approach uses a financial model to assess the
decision to add new capacity and to retire existing capacity. The approach to
plant additions is based on a set of generic plant characteristics, financing
assumptions, and economic parameters. This "add/retire" analysis is an iterative
process performed simultaneously with the development of the energy price
forecast and the projected compensation for capacity.
The methodology assesses the feasibility of annual capacity additions based
on a Discounted Cash Flow (DCF) model using net energy revenues determined in
the production-cost simulations and compensation for capacity determined from
the Capacity Compensation Simulation approach. For each increment of new
capacity, a "Go" or "No Go" decision is made based on whether the entrant would
experience sufficient returns (developed in the DCF model) to merit entry. In
addition, economic retirement decisions are made at each step in the iterative
process based on the specific financial and operating characteristics of the
existing plant.
The iterative process begins with the addition of new capacity when needed.
A production-cost run is executed to determine energy prices, dispatch, and
operating costs. The Capacity Compensation Simulation is then performed. Results
for energy and capacity compensation are combined in the DCF model to determine
whether the new unit is a "Go" or "No Go." If the new unit is a "Go," another
new unit is added in that year and the process repeated. This occurs until the
next new unit returns a "No Go." Should the analysis show "No Go," the unit is
removed (e.g., not added).
Annual retirements are determined after new units are added for that year.
A financial analysis of each unit is performed beginning in 2002, combining the
results of the energy and capacity compensation. If the operating profit (loss)
for an existing unit is negative for any five-year consecutive period, it is
retired at the end of the third year of consecutive operating loss. Although the
decision criterion is somewhat subjective, it is interpreted conservatively.
Thus, if a unit loses money for two years, is profitable over the third year,
and then loses money for two more years, the unit is maintained online.
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If units are retired, the iterative process begins again with the addition
of new capacity. In this way, the introduction of new units influences the
retirement of existing units, and the retirement of existing units enables the
introduction of new units. Since the addition of new units is "lumpy," the
iteration generally stops with new generators earning a small increment above
their cost of debt and equity. The addition of one more new unit then pushes
many of the previous additions into losses. This process is repeated
chronologically through the end of the analysis for each year continuing to show
a deficiency after the most recent new unit addition. This approach reflects a
game theoretic concept of a market equilibrium.
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CHAPTER 4
ASSUMPTIONS
4.1 INTRODUCTION
This chapter describes the key assumptions used in the development of the
annual market price forecasts. Based on the assumptions below, PHB Hagler Bailly
simulates the hourly market-clearing price of energy using MULTISYM(TM), a
production-costing framework that allows the characterization of multiple
pricing areas within larger transmission regions. Each major generating unit
within a transmission area is represented individually in the MULTISYM(TM)
production-costing model using unit-specific cost and operating characteristics.
The MULTISYM(TM) model is used to perform an hour-by-hour chronological
simulation of the commitment and dispatch of generation resources. As discussed
in Chapter 3, the output of this model is then used in PHB Hagler Bailly's
Capacity Compensation Market Simulation Model to develop the annual capacity
contribution.
4.2 GENERAL ASSUMPTIONS
- analysis prepared in 2000 real dollars
- study period 2000 through 2029.
4.3 PRICING AREAS
The pricing areas used in the MULTISYM(TM) analysis of the hourly energy
markets are presented in Figure 4-1.
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FIGURE 4-1
WSCC PRICING AREAS
[WSCC PRICING AREA MAP]
4.4 FUEL PRICES
All fuel types were analyzed on either a regional (natural gas and oil) or
plant location (coal) basis in order to capture pricing variations among major
delivery points. The forecast prices for each fuel includes the cost of
transportation to the power plant site. The nuclear fuel price is estimated as
$5.7 per MWh.
4.4.1 NATURAL GAS
PHB Hagler Bailly has not developed an independent forecast, rather PHB
Hagler Bailly has captured divergent market views by relying on four source
forecasts to create a consensus projection of Henry Hub
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natural gas prices. The four forecasts((1)) used in the consensus are from The
Energy Information Administration (EIA)((2)), The Gas Research Institute
(GRI)((3)), The WEFA Group (WEFA) and Standard and Poor's (S&P). Table 4-1
outlines the Henry Hub projection from each of the four source forecasts as well
as the consensus forecast of natural gas prices at the Henry Hub.
TABLE 4-1
HENRY HUB PROJECTIONS (REAL 2000$/MMBTU)
AVERAGE ANNUAL
2000 2005 2010 2015 2020 GROWTH RATE
---- ---- ---- ---- ---- --------------
EIA....................................... 2.56 2.76 3.06 3.19 3.31 1.30%
GRI....................................... 2.44 2.15 2.09 1.97 1.85 -1.38%
WEFA...................................... 2.65 2.50 2.70 2.79 2.86 0.39%
S&P....................................... 2.61 2.24 2.36 2.57 2.75 0.26%
CONSENSUS................................. 2.56 2.41 2.55 2.63 2.69 0.25%
Regional prices throughout the United States were projected based on this
consensus Henry Hub forecast. For all regions modeled, the delivered price is
the sum of the Henry Hub projection, the projected regional basis differential
and other natural gas supply costs including all taxes.
Basis Differentials
Regional differentials from the Henry Hub were projected based on historic
data and adjusted over time to reflect the regional effects of pipeline
infrastructure development, the introduction of new supplies, regulatory shifts
and changes in regional natural gas demand. Key among the elements affecting the
pricing patterns over time are the Alliance pipeline project (bringing
additional Western Canadian supplies into the Unites States Midwest) and
increased access to Canadian supplies in the northeast United States (see Table
4-2).
TABLE 4-2
REFERENCE HUB ASSIGNMENTS FOR DIFFERENTIAL ANALYSIS
REGION REFERENCE HUB
- ------ -------------
Alberta Empress, AB
Arizona Average: Blanco, NM & Topock, CA
British Columbia Kingsgate, BC
California -- Kern River Topock, CA
California -- Northern Malin, OR
California -- Southern Topock, CA
CFE Topock, CA
Colorado Opal, WY
- ---------------
(1) EIA, Annual Energy Outlook 2000, December 1999; GRI 2000 Baseline
Projection, November 1999; The WEFA Group, Natural Gas Outlook 2000, April
2000; S&P Platt's US Energy Outlook, Fall-Winter 1999-2000.
(2) The EIA does not explicitly forecast a Henry Hub price. The EIA Henry Hub
projection is an estimate based on the EIA lower-48 wellhead price forecast
and the historic relationship between that wellhead price and the Henry Hub
price.
(3) The GRI forecast includes price projections only through 2015. The 2020
price is an estimate based on the 2015 price and the GRI price escalation
pattern from 2010-2015.
4-3
236
REGION REFERENCE HUB
- ------ -------------
Idaho (ex. SPP) Gas Daily Northwest
Montana Average: Empress, AB & Opal, WY
Nevada (ex. SPP) Average: Opal, WY & Topock, CA
New Mexico Blanco, NM
SPP-WSCC Gas Daily Northwest
Utah Opal, WY
WA/OR (E&W) Gas Daily Northwest
Wyoming Opal, WY
Additional Natural Gas Supply Costs
In addition to the regional price basis, there are several other elements
of natural gas supply costs. Some are location specific, others apply generally
to all units modeled. Additional supply costs considered are as follows:
- Liquidity Premium -- Regional market centers are usually located at the
interconnection of several interstate pipelines. Many offer loaning and
parking services to help facilitate a liquid and transparent market. It
can be assumed that most generating units do not have immediate access to
such services and, therefore, pay a nominal fee above this market center
price. All units are assumed to incur a liquidity premium as part of
their natural gas supply cost.
- LDC Costs -- Many existing units are located behind Local Distribution
Companies (LDC) and, therefore, must pay an additional variable charge
for natural gas service. Estimates of regional LDC costs are included for
all existing units in the model. It is assumed that market pressure will
result in this charge declining over time to a level that covers the
variable cost of service incurred by these LDCs.
- Transition Surcharges -- Southern California units must pay a transition
charge as part of the state's stranded cost settlement. This charge is
assumed to expire by year-end 2004.
- Long-Haul Transportation Charge -- Northern and Southern California units
not sited on the Kern River pipeline must pay for service on hinshaw
pipelines within the state of California.
- Taxes -- All units in the model are assessed the appropriate state level
taxes on all natural gas consumed. In addition, New York City units pay
an additional city tax on all natural gas consumed.
The total annual delivered price for natural gas in each of the market
regions is presented in Table 4-3.
Natural Gas Price Seasonality
Natural gas prices exhibit significant and predictable seasonal variation.
Consumption increases in the winter as space heating demand increases and falls
in the summer. Prices follow this pattern as well; the seasonal pattern is most
striking in cold weather locations. Dispatch prices in the model reflect the
seasonal effects based on 5-year historic price patterns exhibited at the
regional market centers.
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TABLE 4-3
WSCC DELIVERED NATURAL GAS PRICE (2000$/MMBTU)
AVERAGE
ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 2025 GROWTH RATE
- ------------ ---- ---- ---- ---- ---- ---- -----------
Alberta............................. 2.53 2.37 2.52 2.60 2.66 2.73 0.31%
Arizona............................. 2.75 2.60 2.81 2.89 2.95 3.02 0.38%
British Columbia.................... 2.58 2.42 2.57 2.65 2.72 2.78 0.31%
CFE................................. 2.89 2.72 2.94 3.02 3.08 3.15 0.34%
Colorado............................ 2.58 2.38 2.63 2.71 2.77 2.84 0.37%
Idaho............................... 2.58 2.42 2.57 2.65 2.72 2.78 0.31%
Montana............................. 2.46 2.29 2.48 2.55 2.62 2.68 0.34%
N. California....................... 3.09 2.90 3.13 3.19 3.24 3.31 0.28%
Nevada.............................. 2.80 2.61 2.84 2.93 2.99 3.06 0.36%
New Mexico.......................... 2.60 2.47 2.67 2.76 2.82 2.89 0.42%
S. California -- LDC(1)............. 3.03 2.91 3.10 3.16 3.22 3.29 0.33%
S. California -- Pipeline(2) (Kern
River)............................ 2.77 2.65 2.86 2.95 3.01 3.08 0.43%
SPP................................. 2.61 2.46 2.60 2.69 2.75 2.82 0.31%
Utah................................ 2.63 2.42 2.67 2.75 2.82 2.88 0.38%
Washington.......................... 2.61 2.46 2.60 2.69 2.75 2.82 0.31%
Oregon.............................. 2.46 2.31 2.45 2.53 2.59 2.66 0.31%
Wyoming............................. 2.61 2.40 2.65 2.73 2.80 2.87 0.37%
- ---------------
(1) The LDC price group refers to existing plants that are subject to local LDC
charges.
(2) The Pipeline price group refers to new additions constructed along main gas
pipelines, which will not be subject to LDC charges.
4.4.2 FUEL OIL
Oil price trends were developed using the same four source forecasts as
were used for the natural gas price analysis. Projections of the average
refinery cost of crude oil (refinery acquisition crude "RAC") were taken from
each of the source forecasts to derive a consensus RAC projection. The
escalation rate implicit in this RAC consensus was then applied to historic
commodity No. 2 and No. 6 oil prices. These commodity prices were adjusted for
the cost of delivery as well as to account for state and local taxes to derive a
dispatch price. Table 4-4 outlines the consensus estimates of world oil prices
based on the four source forecasts.
TABLE 4-4
CRUDE OIL PRICE PROJECTION (REAL 2000$/BBL)
AVERAGE
ANNUAL
2000 2005 2010 2015 2020 GROWTH RATE
----- ----- ----- ----- ----- -----------
EIA................................... 21.92 21.19 21.72 22.27 22.80 0.20%
GRI................................... 18.42 18.42 18.42 18.42 18.42 0.00%
WEFA.................................. 24.22 18.74 18.84 19.80 20.81 -0.76%
S&P................................... 21.14 16.50 17.32 19.31 20.72 -0.10%
CONSENSUS............................. 21.42 18.71 19.07 19.95 20.68 -0.18%
4-5
238
NO. 2 FUEL OIL
No. 2 fuel oil prices were derived from historic spot price data, historic
U.S. oil prices and projections of world oil price escalation from the four
source forecasts. Delivered prices are made up of commodity costs,
transportation costs and taxes. First, each state was assigned to a reference
terminal. These reference terminal price projections were calculated by
escalating historic prices at the consensus RAC crude oil price escalation
pattern. All states assigned to the same reference terminal have the same No. 2
oil commodity cost. Table 4-5 details the terminal assignments used.
TABLE 4-5
REFERENCE TERMINAL ASSIGNMENTS FOR
NO. 2 FUEL OIL ANALYSIS
REGION REFERENCE TERMINAL
------ ------------------
Arizona Phoenix
California Los Angeles
Colorado Denver
Idaho Denver
Montana Denver
Oregon Los Angeles
Utah Denver
Washington Denver
Wyoming Denver
The transportation costs for each state is based on an analysis of historic
market center prices and delivered fuel oil at electric generating stations. The
transportation costs is set to the average (real) cost differential between spot
and delivered prices over the 1994-1997 period. Transportation costs for No. 2
fuel oil are projected to remain constant in real terms over the forecast
horizon. The final delivered priced for No. 2 fuel oil in each of the study
regions is shown in Table 4-6.
TABLE 4-6
WSCC DELIVERED NO. 2 OIL PRICE (2000$/MMBTU)
AVERAGE ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 2025 GROWTH RATE(4)
- ------------ ---- ---- ---- ---- ---- ---- --------------
Alberta........................... 5.88 5.16 5.25 5.49 5.68 5.89 0.00%
Arizona........................... 6.37 5.62 5.72 5.96 6.16 6.37 0.00%
British Columbia.................. 5.88 5.16 5.25 5.49 5.68 5.89 0.00%
California........................ 6.63 5.85 5.96 6.21 6.41 6.63 0.00%
CFE............................... 6.57 5.80 5.91 6.15 6.36 6.57 0.00%
Colorado.......................... 6.09 5.40 5.49 5.71 5.90 6.10 0.00%
Idaho (ex. SPP)................... 6.20 5.49 5.59 5.81 6.01 6.21 0.00%
Montana........................... 5.93 5.26 5.35 5.57 5.75 5.94 0.00%
Nevada (ex. SPP).................. 6.28 5.56 5.66 5.89 6.08 6.29 0.00%
New Mexico........................ 6.37 5.62 5.72 5.96 6.16 6.37 0.00%
Oregon............................ 5.61 4.92 5.01 5.23 5.42 5.62 0.00%
SPP............................... 6.28 5.56 5.66 5.89 6.08 6.29 0.00%
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AVERAGE ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 2025 GROWTH RATE(4)
- ------------ ---- ---- ---- ---- ---- ---- --------------
Utah.............................. 6.19 5.48 5.57 5.80 5.99 6.19 0.00%
Washington........................ 5.96 5.23 5.33 5.56 5.76 5.97 0.00%
Wyoming........................... 6.15 5.45 5.54 5.77 5.96 6.16 0.00%
- ---------------
(4) The delivered No. 2 oil prices decline from 2000 to 2005 by approximately
12% and then increase to slightly more than the 2000 value by 2025.
No. 6 Fuel Oil
No. 6 fuel oil prices were derived using the same methodology employed to
derive No. 2 prices. Because residual oil is so thinly traded, it is difficult
to identify significant regional price premiums. As a result, commodity prices
for all regions were based on either 1% sulfur residual oil at New York Harbor
or the Platt's 1% sulfur U.S. West Coast price quote.
The transportation costs for each state is calculated as the difference
between delivered residual oil at electric generating stations and market center
prices based on the assigned terminal. The transportation cost is set to the
average (real) cost differential between spot and delivered prices over the
1994-1997 period. Transportation costs for No. 6 fuel oil are projected to
remain constant in real terms over the forecast horizon. The final delivered
price for No. 6 fuel oil is presented in Table 4-7.
TABLE 4-7
WSCC DELIVERED NO. 6 FUEL OIL PRICE (2000$/MMBTU)
AVERAGE ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 2025 GROWTH RATE(5)
- ------------ ---- ---- ---- ---- ---- ---- --------------
Alberta........................... 3.05 2.67 2.72 2.84 2.95 3.06 0.00%
Arizona........................... 3.05 2.67 2.72 2.84 2.95 3.06 0.00%
British Columbia.................. 3.05 2.67 2.72 2.84 2.95 3.06 0.00%
California........................ 2.83 2.44 2.50 2.62 2.73 2.84 0.00%
CFE............................... 2.81 2.42 2.47 2.59 2.70 2.81 0.00%
Colorado.......................... 3.75 3.37 3.42 3.55 3.65 3.76 0.00%
Idaho (ex. SPP)................... 3.81 3.42 3.48 3.60 3.70 3.81 0.00%
Montana........................... 3.66 3.30 3.35 3.46 3.56 3.67 0.00%
Nevada (ex. SPP).................. 3.85 3.46 3.51 3.64 3.75 3.86 0.00%
New Mexico........................ 3.05 2.67 2.72 2.84 2.95 3.06 0.00%
Oregon............................ 2.91 2.54 2.59 2.71 2.81 2.91 0.00%
SPP............................... 3.85 3.46 3.51 3.64 3.75 3.86 0.00%
Utah.............................. 3.80 3.42 3.47 3.59 3.70 3.81 0.00%
Washington........................ 3.10 2.70 2.76 2.88 2.99 3.10 0.00%
Wyoming........................... 3.78 3.40 3.45 3.58 3.68 3.79 0.00%
- ---------------
(5) The delivered No. 6 oil prices decline from 2000 to 2005 by approximately
12% and then increase to slightly more than the 2000 value by 2025.
4.4.3 COAL
PHB Hagler Bailly developed a forecast of marginal delivered coal prices
and the corresponding SO(2) allowance prices. The SO(2) prices are presented in
Section 4.7.1. PHB Hagler Bailly developed a base case forecast of annual
average marginal delivered coal prices (in real dollars) for the period 2000
through 2029 on a unit-by-unit basis for electric generators in each region.
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In cost-based electric dispatch modeling, the marginal variable cost of
production is expected to determine dispatch order and the wholesale market
price of electricity. For this reason, PHB Hagler Bailly has provided marginal
delivered coal costs. These costs reflect PHB Hagler Bailly's projection of a
particular unit's marginal coal selection and market pricing for that coal, as
well as the cost of transportation for such marginal purchases. If a particular
unit purchases some higher-cost coal under long-term contracts, the unit's
average cost of coal acquisition will be different from its marginal coal
acquisition cost. It is expected that the cost of higher-priced, contract coal
will not be reflected in dispatch pricing or in market prices for electricity.
Delivered coal prices were projected in two components: (1) coal costs at
the mine (on a FOB basis), and (2) transportation costs.((6)) Because individual
units within a plant sometimes burn different coals, coal selection and
delivered pricing was developed on a unit-by-unit basis.
Coal selection for individual units reflects differing requirements for
compliance with emissions regulations over time, as well as economics. The use
of scrubbers, requirements to comply with Phase I and/or Phase II of the Clean
Air Act Amendments of 1990 (CAAA), and requirements for compliance with New
Source Performance Standards (NSPS) and State Implementation Plan (SIP) limits
were considered, along with the variable costs of different methods of CAAA
compliance. While a unit's historical coal selection was an important factor in
the projections, substitutions of coal types were projected for several units
over time as delivered price economics (including allowance prices) are expected
to change.
FOB mine costs were projected with consideration of productivity increases
and supply and demand economics for different coal types in an integrated market
analysis. The coal price forecast is conservative in that only approximately
one-half of total historical total factor productivity improvements are
reflected in projected price decreases. Projected productivity gains and
competition in supply drove projections of real price decreases for some coals.
For other coals, supply limitations were projected to offset productivity gains
and to keep prices flat or minimize price decreases over time. Various quality
coals are expected to be related to other coals in the same supply region based
on energy content and sulfur content (through projected allowance prices).
Projected transportation costs are based on available delivery options at
each plant for the coal types selected for each unit. Transportation modes
included rail, barge, truck, and minemouth plant transportation. The cost of
rail transportation in different regions of the country was projected to vary
over time, and the costs of alternative transportation modes were projected
separately. Particular units' projected total transportation costs were
calculated as the sum of these separately escalated components.
In addition, potential future changes in transportation options were
considered. In some cases, for example, PHB Hagler Bailly projected the addition
of rail or vessel receiving capability. Potential future rail regulatory relief
was also projected for some plants without access to competitive transportation
options.
Regional specific coal discussions are provided in greater detail in
Appendix A.
4.5 DEMAND AND ENERGY FORECASTS
Annual demand and energy forecast values are based on the 1999 WSCC Load
and Resource Report, except California, where the forecast values are based on
the individual utility data from the 1999 FERC 714 Report.((7)) Based on the
1999 WSCC Load and Resource Report, the average annual growth for the Northwest
Region for the period 2000 through 2029 was assumed to be 0.9%.
The hourly data for the analysis is based on a synthetic hourly load shape
based on five years of actual hourly data (1992-1996) provided with the
MULTISYM(TM) production-costing model to represent the native
- ---------------
(6) "Free on Board," indicating that the price includes the costs of loading
coal onto a train, truck, or barge.
(7) Energy Information Administration, Form EIA-411, Western System Coordinating
Council, Summary of Estimated Loads and Resources, Data as of January 1,
1999, April 1999. Federal Energy Regulatory Commission, Form 714: Annual
Electric Control and Planning Area Report, 1999.
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241
load requirements for each of the pricing areas. The annual demand and energy
forecast values are applied to the native hourly load requirements to develop
the forecasted hourly loads for each year of the analysis.
4.6 ELECTRICITY IMPORTS
Imports and exports between transmission areas are determined by the model
using inputs for transfer capabilities, wheeling rates, and line losses. The
wheeling rates between pricing areas in the WSCC were assumed to be $2.00/MWh
for all pricing areas except Montana. For Montana, the wheeling rate was assumed
to be $5.00/MWh through 2004, and then reduced to $2.00/MWh to reflect an
estimated reduction in pricing from the formation of a regional transmission
organization. Wheeling rates within the California ISO were set to $0.00/MWh.
The inputs for transfer capability are shown in Appendix B.
4.7 EXISTING GENERATION UNITS
4.7.1 FOSSIL UNITS
Each of the existing fossil generating units in the model is characterized
using the following parameters((8)):
- summer and winter net capability
- average heat-rate curve (4 points)
- operating characteristics
- minimum capacity
- ramp rate
- minimum uptime
- minimum downtime;
- forced outage rate
- scheduled maintenance rate
- variable operation and maintenance (O&M) cost
- emission costs
- start fuel.
Summer and Winter Capabilities
The summer and winter capability values were obtained from the 1999 WSCC
Load and Resource Report.
Heat-Rate Curves for Fossil Units
Heat rate data is initially applied using the Energy Information
Administration (EIA) Form EIA-860. This form contains data, including full-load
heat rates, for existing electric generating plants and for new plants scheduled
for initial commercial operation within 10 years of the filing of the report.
Full load heat rate values were established according to the 1995 Form
EIA-860.((9)) This is the most recent year the report was published. PHB Hagler
Bailly then uses this information to develop heat rate curves based on generic
assumptions by unit type.
Operating Characteristics
Generating unit operating characteristics (i.e., minimum capacity, ramp
rate, minimum uptime, and minimum downtime) were estimated by PHB Hagler Bailly
based on typical characteristics by unit type.
- ---------------
(8) Unit characteristics related to output, heat rate, and forced outage rates
for the PPL Montana assets were provided by R.W. Beck.
(9) Energy Information Administration, Form EIA-860, 1995.
4-9
242
Scheduled and Forced Outage Rates
The scheduled maintenance outage rates and equivalent forced outage rates
for all fossil units were estimated by PHB Hagler Bailly based on historical
data for comparable units contained in the GADS data base.((10))
Variable Operation and Maintenance Costs
Each generating unit's variable operation and maintenance cost is
represented by PHB Hagler Bailly's default values (see section 4.8.1). The
values used are as follows: $4/MWh for scrubbed steam-coal units, $3/MWh for
other steam-coal units, $2/MWh for steam-gas and oil units, $2/MWh for combined
cycle units, and $5/MWh for peaking units (includes combustion turbine units,
internal combustion units, and jet engines).
Sulfur Dioxide Emission Costs
Title IV of the Clean Air Act awarded tradable SO(2) emission allowances to
certain "grandfathered" plants in existence. Each allowance gives the plant
owner the right to emit one ton of SO(2) for one year. Congress' intent was to
reduce the total number of tons of SO(2) emissions by awarding emission
allowances for less SO(2) than a plant had emitted in previous years. These
allowances were awarded in two phases; one beginning in 1995; the other in 2000.
In this study we assume that the SO(2) emission costs a generating unit
incurs in any future year is determined by the number of tons of SO(2) it emits,
after installation of cost-effective control technologies, multiplied by the
price of allowances in that year. We added this cost to the variable cost of the
generating unit emitting the SO(2) and included the capital and operating costs
of any abatement equipment in the total capital and operating costs of the
generating unit.
PHB Hagler Bailly developed a price forecast for SO(2) allowances. Starting
with a value of $213 per ton in 2000, PHB Hagler Bailly projects the price of
SO(2) emission allowances to increase at a real rate of 6.65% per year between
2000 and 2010, reflecting a market discount consistent with the expected rate of
return required to justify holding "banked" SO(2) allowances (see Table 4-9). By
2010 the real cost of allowances is projected to plateau at $406 per ton (in
2000 dollars), a level determined by the equivalent cost of releasing allowances
by installing flue gas desulfurization equipment at existing plants.((11))
TABLE 4-9
SO(2) COST CURVES (2000$/TON)
YEAR SO(2) YEAR SO(2) YEAR SO(2)
- ---- ----- ---- ----- ----------- -----
2000 $213 2004 $276 2008 $357
2001 $227 2005 $294 2009 $381
2002 $243 2006 $314 2010 - 2029 $406
2003 $259 2007 $335
4.7.2 HYDROELECTRIC UNITS
The hydroelectric plants are consolidated by utility and categorized as
peaking or baseload. Similar to the thermal units, the maximum capacity for each
unit was taken from the sources cited above for summer and
- ---------------
(10) North American Electricity Reliability Counsel, Generating Availability
Data System (GADS), Equipment Availability Report (1991-1996), 1997.
(11) This assumes a continuation of current regulations under the 1990 Clean Air
Act Amendments. Proposals are under consideration by EPA (e.g., controls on
fine particulates) that could change these regulations.
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243
winter capabilities. Monthly energy patterns were developed from the 1991-1999
EIA Forms 759, which contain monthly generation and (for pumped storage units)
net inflows.
4.7.3 NUCLEAR UNITS
PHB Hagler Bailly evaluated the operation of nuclear plants in the regions
covered by this study on the basis of operating experience and going forward
costs to determine which plants remain in service.
To conduct the operating experience assessment, PHB Hagler Bailly utilized
two proprietary PHB Hagler Bailly databases of nuclear power information: the
Nuclear Power Experience (NPE), and the Operating Plant Evaluation Code (OPEC).
NPE is a database of all safety-related events that have occurred in the United
States. OPEC is a database that tracks the performance of all U.S. nuclear units
(400 MW or larger), containing approximately 130,000 event records that document
over 1,500 unit-years of experience. The operating experience assessment was
used to then evaluate the probable shutdown dates of the nuclear units in
question.
To evaluate shutdown dates, several major issues were considered. The most
important issue was plant competitiveness. Many nuclear stations are viewed as
expensive because of the high capital costs for original construction. Since no
new stations are being built, this is treated as a sunk cost and is not
considered in the determination of the competitiveness of a station. Sunk
capital costs for original construction will not determine a unit's competitive
position in the future.
The competitiveness of each unit can be evaluated with two essential
variables, level of production and costs. Because nuclear units are typically
base loaded and reserve shutdown hours are very low, PHB Hagler Bailly uses
capacity factor to measure production. Going forward costs include three
components: operations and maintenance (O&M), capital addition costs, and fuel
costs. The capital addition costs do not include the original investment in the
plant and only include modifications made to the plant each year. These costs
are very difficult to track due to the reporting methods. In recent years, the
number of modifications to nuclear power stations have decreased and these costs
are relatively low compared to O&M costs. Thus, PHB Hagler Bailly has not
considered capital costs in this analysis. Fuel costs are also relatively low
and have been predictable and stable over the past decade. Given the greater
importance of many of the other major variables, PHB Hagler Bailly did not
consider fuel costs as an important factor and did not evaluate them in the
analysis.
In addition to the competitiveness of the station, there are a number of
other issues that might affect a shutdown date. Politics of the region plays an
important part in the premature shutdown of the units. Equipment failures and
poor overall performance can also cause a utility to shutdown a unit before its
license expires. As the units age, the amount of investment required to continue
operating the unit becomes an important factor. Issues such as locations that
assist in voltage regulation, restrictions due to transmission, and restrictions
due to environmental regulation must also be considered. PHB Hagler Bailly
specifically addressed each of the following for each of the units analyzed:
- SIZE OF UNIT. Larger units provide more benefit to the utility when the
unit is operating and represent a larger investment loss by the utility
if the unit is shutdown.
- AGE OF UNIT. Nuclear power plants are licensed for 40 years. PHB Hagler
Bailly has conducted studies showing that generating power stations begin
to require life extension costs between 30 and 40 years. Thus, the older
a station gets, the more it is expected to spend and the less competitive
a station becomes.
- NUMBER OF UNITS OPERATED BY UTILITY. If a utility has more than one
unit, it has more corporate overhead costs associated with the nuclear
power generation allocated to more than one station. In addition, the
utility is more likely to be committed to operating its nuclear power
generation.
- PERFORMANCE. Typically the poorer performing units (units that are shut
down for extended periods of time or have many forced outages) are viewed
as noncompetitive. Even if the unit is able to overcome
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244
the existing difficulty causing the shutdown, the perception that the
unit is uneconomic is difficult to overcome.
Historical performance as well as recent trends in forced outage rates at
each unit were reviewed. Future forced outage rates were forecast for each year,
and each unit's scheduled outages during the year were also considered. From
this information, and noting that outages are becoming shorter as the industry
improves outage planning, the duration of outages for each unit was forecast.
For refueling outages, sources included refueling outage schedules, published
every six months in Nuclear News for all U.S. units.
In addition to the operating experience assessment, PHB Hagler Bailly
estimated the annual going forward costs (fixed O&M, property taxes, and
annualized incremental capital costs) associated with each unit. For this
assessment, Table 4-10 summarizes the nuclear units projected to retire before
their 40-year operating life is completed:
TABLE 4-10
WSCC NUCLEAR UNIT RETIREMENTS
UNIT CAPACITY RETIREMENT DATE
- ---- -------- ---------------
WNP 2....................................................... 1170 12/31/05
4.8 CAPACITY COMPENSATION MARKET SIMULATION MODEL INPUT ASSUMPTIONS
4.8.1 EXISTING UNITS GOING-FORWARD COSTS
PHB Hagler Bailly developed projections of Fixed Operation & Maintenance
(FO&M) costs for steam generating units. FO&M costs are intended to include all
forward (non-sunk) costs of operating and maintaining plants, except those
variable costs, such as fuel costs, which are included in the dispatch cost.
Total O&M expenses, excluding fuel expenses, rents, and allowances were obtained
from the OPRI Database of Form 1 data. Internal estimates of Variable Operation
& Maintenance (VO&M) costs (see Section 4.7.1) were used in conjunction with the
data to net the variable portion out of total O&M expenses, generating a value
for FO&M for each plant.
Estimates of pension and benefit expenses, based on the number of full-time
employees at each station, were also obtained from Form 1 data and added to the
FO&M estimate for each plant.
FO&M estimates were developed for broad prime mover, fuel type, and size
categories. For example, coal steam plants were grouped together, as were all
oil and gas fired steam plants. Plants in each of these groups were further
grouped by size categories. Plants in each resulting grouping were then ranked
according to FO&M value.
To account for an expected reduction in FO&M costs over time in a
deregulated environment, the cost for the plant at the 25(th) percentile in each
grouping (lower percentiles indicating lower costs) was taken as an appropriate
value for the 50(th) percentile of plants in the same grouping for 2005.
Estimates of annual incremental capital expenditures were based on a ten-year
national average of capital additions to utility steam generating plants. These
estimates were added to the FO&M cost figures to develop a total annual going-
forward cost. After 2010, FO&M costs were assumed to decrease at a constant rate
of 3% per year, equivalent to the average rate of worker productivity
improvement in the U.S. industrial sector over the past several decades.
Property tax data for each unit was derived by applying an estimated mill
levy rate to an assumed market value.
4.8.2 CAPACITY ADDITIONS THROUGH 2002
A critical step in simulating the regional capacity market is to ascertain
the number and timing of capacity additions for the near term (2000 through
2002). To this end, PHB Hagler Bailly worked toward the following goals:
determining the number and status of greenfield power plants that are currently
under development in the regions, determining the average length of time
required to construct and operate a new
4-12
245
power plant in the regions, and determining the costs associated with
constructing and operating a power plant in the regions.
In order to collect and analyze sufficient data to meet these goals, PHB
Hagler Bailly completed a number of separate tasks. Staff performed a literature
search for the past year in an effort to identify articles referring to planned
power plant development in the regions. Also, PHB Hagler Bailly's experts
analyzed PHB Hagler Bailly's IPP Database to determine the number of plants
currently under development in the regions and also the average length of time
required to bring a plant on line following the announcement of a new project.
As a result of PHB Hagler Bailly's analysis and investigation, a baseline
on-line scenario was developed which reflects PHB Hagler Bailly's estimate of
the plants that will realistically be constructed in the target region through
the year 2002. These are summarized in Table 4-11.
TABLE 4-11
WSCC BASE CASE CAPACITY ADDITIONS(1)
DEVELOPER SIZE(2) UNIT TYPE FUEL TYPE BASE CASE
- --------- ------- --------- ----------- ---------
ARIZONA/NEW MEXICO/S. NEVADA
Cobisa (Person)..................................... 140 GT Natural Gas 6/1/2000
Calpine (Mojave).................................... 540 CC Natural Gas 1/1/2001
PPL Global/Duke (Griffith).......................... 600 CC Natural Gas 7/1/2001
Reliant Energy (Casa Grande)........................ 500 CC Natural Gas 7/1/2001
Panda Energy (Gila Bend)............................ 2000 CC Natural Gas 11/1/2002
Calpine (W. Phoenix)................................ 620 CC Natural Gas 11/1/2002
CALIFORNIA
Sunrise Cogen (Sunrise)............................. 320 GT Natural Gas 5/1/2001
Calpine (Los Medanos)............................... 500 CC Natural Gas 7/1/2001
Calpine (Sutter).................................... 545 CC Natural Gas 7/1/2001
PG&E Gen (Lapaloma)................................. 1048 CC Natural Gas 11/1/2001
Calpine/Bechtel (Delta)............................. 880 CC Natural Gas 6/1/2002
COLORADO/WYOMING
KN Power (Front Range).............................. 160 GT Natural Gas 5/1/2000
Coastal Power (Manchief)............................ 265 GT Natural Gas 5/1/2000
Black Hills (Boulder)............................... 74 GT Natural Gas 6/1/2000
Black Hills (Denver)................................ 37 GT Natural Gas 6/1/2000
NA Power Corp (DIA)................................. 150 GT Natural Gas 11/1/2002
NORTHWEST (WASHINGTON/OREGON/IDAHO/UTAH/MONTANA/ N.
NEVADA)
FPL Energy (Ever Delta)............................. 248 CC Natural Gas 6/1/2001
Cogentrix (Rathdrum)................................ 270 CC Natural Gas 6/1/2001
Pacificorp (Klamath)................................ 474 CC Natural Gas 7/1/2001
Calpine (Hermiston)................................. 536 CC Natural Gas 7/1/2002
PGE (Coy Springs)................................... 228 CC Natural Gas 11/1/2002
ALBERTA/BRITISH COLUMBIA
Island Cogen Project (Island)....................... 245 GT Natural Gas 5/1/2000
- ---------------
(1) Online dates for the year 2000 are based on projections as of the date of
this analysis.
(2) Maximum net capacity.
4-13
246
4.8.3 CAPACITY ADDITIONS POST 2002
The validity of capacity additions post 2002 is assessed based on a
discounted cash flow (DCF) approach that provides a "Go" or "No Go" decision for
each increment of generic new capacity.
The DCF framework captures the net present value of the various cash flow
streams: revenues, including compensation for capacity and energy; and expenses,
including fixed and variable O&M, fuel, property taxes, and principal and
interest expenses for the new capacity additions. The analysis merges
assumptions concerning the general economy, capital markets, tax structures,
fixed costs, and depreciation with the operating projections for the potential
new capacity in order to capture the gross cash flow from the unit's projected
operation.
Generic Plant Characteristics
The starting point for the DCF calculation is the generic unit-specific
operating parameters for new combined cycle and combustion turbine units. The
generic parameters and assumptions assumed in the model are displayed in Table
4-12. Table 4-13 indicates the assumed schedule and effect of technology
improvement on new unit heat rates.
TABLE 4-12
NEW CC AND CT GENERATING CHARACTERISTICS (2000$)
COMBINED CYCLE COMBUSTION TURBINE
-------------------- --------------------
WSCC-CA WSCC-OTHER WSCC-CA WSCC-OTHER
------- ---------- ------- ----------
Capital Cost ($/kW).............................. $ 575 $ 500 $ 345 $ 315
Fixed O&M ($/kW-year)............................ $10.50 $10.50 $5.50 $5.50
Variable O&M ($/MWh)............................. $ 2.00 $ 2.00 $5.00 $5.00
Size (MW)........................................ 520 520 345 345
TABLE 4-13
FULL LOAD HEAT RATE IMPROVEMENT (BTU/KWH)
2000-2003 2004-2008 2009-2013 2014-2018 2019+
--------- --------- --------- --------- -----
Combined Cycle........................... 6,700 6,566 6,435 6,306 6,180
Combustion............................... 10,400(W) 10,192(W) 9,988(W) 9,788(W) 9,593(W)
Turbine.................................. 10,070(S) 10,487(S) 10,427(S) 10,700(S) 9871(S)
Other Expenses
Information on fixed costs, depreciation and taxes is also developed and
incorporated within the DCF analysis in determining the economic viability of
the new unit additions. Environmental costs and overhaul expenses are not
included, due to expectations that such expenses would be minimal in early years
of operation.
- Property taxes are based on representative averages for similar projects
and are assumed to be 1.1% for California and 1.5% for the rest of WSCC
of the initial capital costs.
- Depreciation of the initial all-in cost of the new combined cycles is
based on a standard 20-year MACRS (150 DB) with mid-year convention (15
years for combustion turbine).
Economic and Financial Assumptions
- Minimum after-tax return is assumed to be 13.5%.
- Financing assumptions are assumed to be 60% debt, 40% equity for combined
cycle units, and 50% debt, 50% equity for combustion turbine units.
- Debt interest rate is assumed to be 9.1% based on 30 year U.S. Treasuries
plus 250 basis points. Debt terms are 20 years with mortgage-style
amortization for combined cycle units and 15 years for combustion turbine
units.
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CHAPTER 5
MARKET PRICE FORECASTS
5.1 INTRODUCTION
Using the assumptions presented in Chapter 4, we developed a "Base Case"
which reflects our best assessment of future market conditions. It should be
recognized that this Base Case will vary to the extent the input assumptions
change, and such assumptions should be reviewed with the same rigor as the
resulting forecast.
The market price forecast is composed of two revenue components: those
associated with the system marginal cost of producing energy, and the additional
compensation for capacity that must be present in the market (above and beyond
the system marginal cost) to ensure that adequate generation capacity is
available in the market.((1)) This compensation for capacity is developed on an
average across the Northwest region and will apply to each individual unit
depending on its characteristics.
Market price forecast are presented for three pricing regions: Montana, the
physical location of the assets; Washington Oregon East, representative of the
Mid-Columbia spot market; and Washington Oregon West, a major contractual point
of delivery for power generated by the other owners of the Colstrip generating
units. In addition to directly marketing the output of the portfolio of assets
in Montana, PPL Montana has the ability to sell and deliver power to
out-of-state counterparties under open access transmission tariffs with
transmission providers such as the Montana Power Company. PPL Montana also has a
contingent agreement to purchase an interest in the Colstrip Transmission System
from the Montana Power Company. Should PPL Montana purchase an interest in the
Colstrip Transmission System, they expect to market approximately 210 MW of
Colstrip capacity directly to Mid-Columbia counterparties at the Garrison, MT
substation and avoid paying the Montana Power Company open access transmission
tariff.
The energy price forecast presents the marginal cost of generating
electricity in these electricity markets. The additional compensation for
capacity needed to maintain a minimum amount of capacity in the market is
factored into the All-In market price forecast. Thus, the All-In price is a good
representation of the average price needed in the marketplace to maintain
equilibrium. It should be noted that the amount of compensation for capacity
needed in the market is directly related to the energy price level and the
ability of the marginal unit to recover its fixed costs. As energy prices rise
and fall, compensation for capacity will also adjust to ensure that the total
going-forward costs of the marginal unit are met. As a result of this dynamic
equilibrium, the revenues, which form the All-In market price, should be
sufficient to support the minimum amount of capacity needed by the system.
Compensation for capacity may take many forms. Payments could be in the
form of compensation for capacity arising from a capacity market, a regulated
payment fee, bilateral contracts, payments by the ISO for ancillary services, or
in the form of prices above the marginal cost of the price-setting plant.
Ultimately, the compensation for capacity will reflect what customers are
willing to pay for reliability.
In each year, the value of the additional compensation for capacity is
assumed to be capped at the annual carrying cost of a new combustion turbine. If
the additional compensation for capacity were higher than the carrying cost of a
new combustion turbine, then a new combustion turbine would be constructed to
displace other higher cost units in the system.
- ---------------
(1) If additional compensation for capacity were not present in the market, then
a substantial portion of the generating capacity necessary to meet peak
demand, let alone necessary to maintain an economic level of reserves, would
exit the market as these plants would not be able to cover their
going-forward costs. Such a forecast is nonsensical; therefore the energy
price generated by the model should not be considered without factoring in
the value of the assets needed to maintain reliability in the market.
5-1
248
In addition to the Base Case, PHB Hagler Bailly developed two additional
cases or sensitivities described below:
- "Low Fuel Price Case," which tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu
reduction in the 2000 gas and oil prices with escalation remaining
unchanged (coal prices are not changed).
- "High Hydro Case" which reflects the result of five straight high hydro
seasons (2000-2004) in the WSCC. The high water data is based on the
average of the two highest years in the past ten years. After the initial
five years, the case reverts back to the Base Case (based on the average
flows over the last ten years).
The Low Fuel Price Case represents a reduction of approximately 20% in the
fuel price. We believe that this represents a good example of the fuel price
fluctuations (downward) based on historical information (1996-2000). Also,
because the region is dependent on hydro generation, we developed a High Hydro
Case to represent the potential impact of five consecutive high hydro generation
years with an increase in annual hydro generation of approximately 18% over the
average annual hydro generation assumed in the Base Case. These sensitivities
have been developed to portray the impact of changes in critical assumptions,
and do not necessarily present a "worst" case scenario.
Section 5.2 presents tables and graphs describing the current market
conditions in the Northwest. Section 5.3 and 5.4 present analyses of the market
price forecasts for the Base Case and the sensitivity cases, respectively.
Energy prices were developed for the Montana, Washington Oregon East, and
Washington Oregon West markets and an All-In market price forecast is provided
for these markets utilizing the methodology outlined in Chapter 3 (assuming a
100% load factor).
Appendix D presents sample Base Case supply curves for the Northwest energy
market, showing the relative costs of PPL Montana's assets in the marketplace at
different points in time. The dispatch price shown in the supply curves is based
on the average annual marginal dispatch cost of the resources and does not
include additional capacity compensation.
5.2 NORTHWEST MARKET CONDITIONS
The projected load and resource balance for the Northwest is illustrated in
Figure 5-1. Peak demand growth in the Northwest market is forecast to grow at an
average annual rate of approximately 1% from 2000 through the end of the study
period. As illustrated in Figures 5-2 and 5-3, the Northwest region is very
dependent on hydro generation. The ability of hydro generation to meet demand is
dependent on the availability of water. To reflect this in the load and resource
balance chart, the capacity of the hydro generation in the region was decreased
by 6% based on BPA's adjustment for instantaneous generating capacity, which
reflects the maximum generation under optimum conditions assuming critical water
conditions (i.e., the lowest water year).
A required system-wide reserve margin of approximately 8% is assumed in the
analysis. As shown in Figure 5-1, the existing capacity is initially sufficient
to meet an 8% reserve margin.
As illustrated in Figure 5-2 and Figure 5-3, which are based on data for
2000, the Northwest is largely dependent on hydro generation (approximately 69%
of the installed capacity in the market). Coal-fired generation accounts for
approximately 18% of the installed capacity in the region. The region has a
relatively small amount of nuclear generation (approximately 2%). Gas and oil
fired generation represent approximately 8% of the installed capacity.
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249
FIGURE 5-1
NORTHWEST LOAD AND RESOURCE BALANCE
[LINE GRAPH]
(1) 8% reserve margin assumed.
Source: 1999 WSCC Load and Resource Report.
FIGURE 5-2
NORTHWEST CAPACITY
[PIE GRAPH]
FIGURE 5-3
NORTHWEST ENERGY
[PIE GRAPH]
5.2.1 BASE CASE ANALYSIS
The market price forecast is developed based on the marginal energy costs
and the going-forward costs of the marginal unit on the supply curve as
discussed in Chapter 3. The marginal energy price forecast presents the marginal
cost of generating electricity in the market. The additional compensation for
capacity needed to maintain a minimum amount of capacity in the market is
factored in to the All-In market price forecast.
The amount of compensation for capacity needed in the market is directly
related to the energy price level and the ability of the marginal unit to
recover its fixed costs. As energy prices rise and fall, compensation
5-3
250
for capacity will also adjust, based on our methodology, to ensure that the
total going-forward costs of the marginal unit are met.
The Base Case compensation for capacity forecast for the Northwest market
is presented in Table 5-1. As described in Chapter 3, the capacity compensation
is based on the intersection of the supply curve for capacity and the demand
curve for reliability. The capacity compensation begins initially at
approximately $13/kW-yr. The compensation fluctuates in the first few years as
new units are added into the analysis and begin to set the compensation level.
In the later years of the analysis, the compensation increases as more units are
added to maintain the estimated reserve requirements of the Northwest and the
energy margins decline for the unit setting the compensation level.
TABLE 5-1
NORTHWEST BASE CASE
COMPENSATION FOR CAPACITY FORECAST* ($/KW-YR)
2000 13.10 2010 9.00 2020 25.40
2001 17.90 2011 6.90 2021 26.40
2002 24.40 2012 9.10 2022 28.90
2003 9.70 2013 13.10 2023 30.30
2004 16.90 2014 18.60 2024 35.50
2005 8.70 2015 16.10 2025 33.30
2006 6.80 2016 18.10 2026 33.90
2007 6.60 2017 18.00 2027 33.90
2008 9.20 2018 22.30 2028 29.90
2009 11.50 2019 25.50 2029 27.70
- ---------------
* Results are expressed in real 2000 dollars.
5.2.2 MONTANA ENERGY AND ALL-IN PRICE FORECAST
The energy price forecast and All-In price forecast for Montana are
presented in Table 5-2, and graphically in Figure 5-4. The energy price declines
as new generation enters the WSCC market. Since the Montana pricing area is a
net exporter of energy, the prices reflect Montana's ability to market its lower
cost resources to higher priced regions.
TABLE 5-2
MONTANA-BASE CASE ENERGY AND ALL-IN PRICE FORECASTS*
ENERGY PRICE FORECAST ($/MWH) ALL-IN PRICE FORECAST ($/MWH)
- ------------------------------ -------------------------------
2000 25.20 2015 24.20 2000 26.70 2015 26.00
2001 24.50 2016 23.70 2001 26.50 2016 25.80
2002 23.80 2017 24.00 2002 26.60 2017 26.00
2003 24.90 2018 23.40 2003 26.00 2018 26.00
2004 25.00 2019 23.50 2004 26.90 2019 26.40
2005 24.70 2020 23.50 2005 25.00 2020 26.40
2006 24.00 2021 23.40 2006 24.70 2021 26.40
2007 24.10 2022 23.50 2007 24.80 2022 26.80
2008 24.40 2023 23.50 2008 25.40 2023 27.00
2009 24.20 2024 23.10 2009 25.50 2024 27.00
2010 24.70 2025 23.40 2010 25.70 2025 27.20
2011 24.50 2026 23.80 2011 25.30 2026 27.60
5-4
251
ENERGY PRICE FORECAST ($/MWH) ALL-IN PRICE FORECAST ($/MWH)
- ------------------------------ -------------------------------
2012 24.50 2027 23.80 2012 25.60 2027 27.70
2013 24.60 2028 24.50 2013 26.10 2028 27.90
2014 24.30 2029 25.20 2014 26.40 2029 28.30
- ---------------
* Results are expressed in real 2000 dollars.
FIGURE 5-4
MONTANA ENERGY AND ALL-IN MARKET PRICE FORECASTS
[LINE GRAPH]
5.2.3 WASHINGTON OREGON EAST
The energy price forecast and All-In price forecast for Washington Oregon
East are presented in Table 5-3, and graphically in Figure 5-5. The prices are
higher than Montana for most of the years in the study period. The All-In prices
reflect both the change in energy prices, and the change in capacity
compensation. In the initial years of the study, new resources are added to the
WSCC and the prices in the Northwest decline. After the first few years, the
energy prices continue to decline, the capacity compensation increases, and the
All-In prices remain relatively constant throughout the study period.
TABLE 5-3
WASHINGTON OREGON EAST BASE CASE ENERGY AND ALL-IN PRICE FORECASTS*
ENERGY PRICE FORECAST ($/MWH) ALL-IN PRICE FORECAST ($/MWH)
- -------------------------------- ------------------------------
2000 27.80 2015 25.40 2000 29.30 2015 27.30
2001 26.80 2016 25.00 2001 28.90 2016 27.10
2002 25.70 2017 25.00 2002 28.50 2017 27.10
2003 26.90 2018 24.50 2003 28.00 2018 27.10
2004 26.80 2019 24.30 2004 28.70 2019 27.20
2005 26.10 2020 24.30 2005 27.10 2020 27.20
5-5
252
ENERGY PRICE FORECAST ($/MWH) ALL-IN PRICE FORECAST ($/MWH)
- -------------------------------- ------------------------------
2006 25.90 2021 24.20 2006 26.60 2021 27.20
2007 25.80 2022 23.90 2007 26.50 2022 27.20
2008 25.90 2023 23.70 2008 26.90 2023 27.20
2009 25.50 2024 23.10 2009 26.80 2024 27.20
2010 25.80 2025 23.40 2010 26.90 2025 27.20
2011 26.20 2026 23.40 2011 27.00 2026 27.30
2012 26.00 2027 23.40 2012 27.00 2027 27.30
2013 25.80 2028 24.10 2013 27.30 2028 27.50
2014 25.60 2029 24.40 2014 27.70 2029 27.50
- ---------------
* Results are expressed in real 2000 dollars.
FIGURE 5-5
WASHINGTON OREGON EAST ENERGY AND ALL-IN MARKET PRICE FORECASTS
[LINE GRAPH]
5.2.4 WASHINGTON OREGON WEST
The energy price forecast and All-In price forecast for Washington Oregon
West are presented in Table 5-4, and graphically in Figure 5-6. Similar to the
Washington Oregon East results, the prices in Washington Oregon West are higher
than the Montana region for most of the study period. The initial years show a
decline in prices, as new generation is assumed to be added to the WSCC. In the
later years of the analysis, the energy prices decline and the capacity
compensation increases, resulting in relatively flat All-In prices for the rest
of the study period.
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253
TABLE 5-4
WASHINGTON OREGON WEST BASE CASE ENERGY AND ALL-IN PRICE FORECASTS*
ENERGY PRICE FORECAST ($/MWH) ALL-IN PRICE FORECAST ($/MWH)
- -------------------------------- ------------------------------
2000 28.40 2015 25.90 2000 29.90 2015 27.70
2001 27.40 2016 25.50 2001 29.40 2016 27.50
2002 26.30 2017 25.40 2002 29.00 2017 27.50
2003 27.40 2018 24.90 2003 28.50 2018 27.40
2004 27.30 2019 24.60 2004 29.30 2019 27.50
2005 26.70 2020 24.60 2005 27.60 2020 27.50
2006 26.40 2021 24.50 2006 27.10 2021 27.50
2007 26.30 2022 24.30 2007 27.10 2022 27.50
2008 26.40 2023 24.10 2008 27.40 2023 27.50
2009 25.90 2024 23.40 2009 27.20 2024 27.50
2010 26.30 2025 23.80 2010 27.30 2025 27.60
2011 26.60 2026 23.70 2011 27.40 2026 27.50
2012 26.40 2027 23.70 2012 27.50 2027 27.50
2013 26.30 2028 24.40 2013 27.80 2028 27.80
2014 26.00 2029 24.60 2014 28.10 2029 27.80
- ---------------
* Results are expressed in real 2000 dollars.
FIGURE 5-6
WASHINGTON OREGON WEST ENERGY AND ALL-IN MARKET PRICE FORECASTS
[LINE GRAPH]
5-7
254
5.3 SENSITIVITY CASES
Two sensitivity cases were developed to assess the impact of major changes
in assumptions on the Base Case market price forecasts. The first sensitivity
case examined the effect of lower natural gas and oil prices. Since fuel oil and
natural gas are the marginal fuels in several of the transmission or pricing
areas, the energy price forecast is driven in large part by the forecasted price
of these fuels. In order to test the sensitivity of the Base Case energy price
forecast to changes in the natural gas and fuel oil forecasts, we developed the
Low Fuel Price Case. This case tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu reduction in
the 2000 gas and oil prices, but with the same escalation as used in the Base
Case. No change was made to the forecasted prices of coal.
The second sensitivity case, the High Hydro Case, examined the effect of
five consecutive years of high hydro generation from 2000 through 2004. The high
water year is based on the average of the two highest years in the past ten
years.
As described in Chapter 3, the energy price and capacity compensation are
directly related. This is illustrated in the Low Fuel Price Case and the initial
years of the High Hydro Case. The Low Fuel Price Case energy prices decreased as
compared to the Base Case and the capacity compensation increased.
The increase in hydroelectric generation in the initial years of the High
Hydro Case depresses energy prices. The marginal supply unit receives less
energy margins, and the compensation for capacity increases as compared to the
Base Case. The reduction in prices in the High Hydro Case moves out the entry of
generic new generation in the Northwest until 2005. The capacity compensation is
slightly different than the Base Case after 2004 because of the change in
generic unit additions.
The Low Fuel Price Case and High Hydro Case compensation for capacity
forecasts for the Northwest market are presented in Table 5-5.
TABLE 5-5
NORTHWEST SENSITIVITY CASES COMPENSATION FOR CAPACITY FORECASTS*
LOW FUEL PRICE ($/KW-YR) HIGH HYDRO ($/KW-YR)
- ---------------------------- ------------------------------
2000 26.60 2015 17.50 2000 30.90 2015 14.90
2001 31.90 2016 20.80 2001 33.40 2016 18.50
2002 30.90 2017 19.20 2002 30.90 2017 17.40
2003 9.70 2018 22.40 2003 30.90 2018 22.10
2004 23.20 2019 25.70 2004 30.90 2019 25.70
2005 9.50 2020 25.00 2005 8.70 2020 25.70
2006 10.50 2021 25.90 2006 6.00 2021 26.80
2007 11.30 2022 27.70 2007 6.80 2022 28.50
2008 11.70 2023 29.10 2008 6.70 2023 30.20
2009 15.90 2024 32.80 2009 11.00 2024 35.30
2010 13.20 2025 30.80 2010 8.90 2025 33.30
2011 11.90 2026 32.10 2011 8.00 2026 34.20
2012 13.20 2027 31.70 2012 9.10 2027 33.40
2013 14.70 2028 28.40 2013 11.20 2028 29.20
2014 19.50 2029 26.50 2014 17.10 2029 27.10
- ---------------
* Results are expressed in real 2000 dollars.
5-8
255
5.3.1 MONTANA ENERGY AND ALL-IN PRICE FORECASTS SENSITIVITY CASES
The sensitivity cases energy price forecast and All-In price forecast for
Montana are presented in Tables 5-6 and 5-7. A comparison of the All-In prices
for the Base Case, Low Fuel Price Case, and High Hydro Case is illustrated in
Figure 5-7.
TABLE 5-6
MONTANA SENSITIVITY CASES ENERGY PRICE FORECASTS*
LOW FUEL PRICE ($/MWH) HIGH HYDRO ($/MWH)
- ---------------------------- ------------------------------
2000 21.70 2015 20.50 2000 20.60 2015 24.20
2001 21.00 2016 20.00 2001 20.10 2016 23.60
2002 20.70 2017 20.20 2002 19.80 2017 24.00
2003 21.20 2018 19.80 2003 21.10 2018 23.50
2004 21.30 2019 19.80 2004 20.90 2019 23.40
2005 20.30 2020 19.80 2005 24.00 2020 23.40
2006 20.20 2021 19.70 2006 24.00 2021 23.40
2007 20.40 2022 19.90 2007 24.10 2022 23.50
2008 20.60 2023 19.80 2008 24.40 2023 23.50
2009 20.40 2024 19.50 2009 24.20 2024 23.10
2010 20.80 2025 19.80 2010 24.80 2025 23.40
2011 20.50 2026 20.00 2011 24.40 2026 23.70
2012 20.60 2027 20.10 2012 24.50 2027 23.90
2013 20.70 2028 20.70 2013 24.50 2028 24.50
2014 20.40 2029 21.20 2014 24.30 2029 25.20
- ---------------
* Results are expressed in real 2000 dollars.
TABLE 5-7
MONTANA SENSITIVITY CASES ALL-IN PRICE FORECASTS*
LOW FUEL PRICE ($/MWH) HIGH HYDRO ($/MWH)
- ---------------------------- ------------------------------
2000 24.70 2015 22.50 2000 24.10 2015 25.90
2001 24.70 2016 22.40 2001 23.90 2016 25.70
2002 24.20 2017 22.40 2002 23.30 2017 26.00
2003 22.30 2018 22.40 2003 24.60 2018 26.00
2004 24.00 2019 22.70 2004 24.40 2019 26.40
2005 21.40 2020 22.70 2005 25.00 2020 26.30
2006 21.40 2021 22.70 2006 24.60 2021 26.40
2007 21.60 2022 23.10 2007 24.80 2022 26.80
2008 21.90 2023 23.20 2008 25.20 2023 27.00
2009 22.20 2024 23.20 2009 25.40 2024 27.10
2010 22.40 2025 23.30 2010 25.80 2025 27.20
2011 21.90 2026 23.70 2011 25.30 2026 27.60
2012 22.10 2027 23.70 2012 25.50 2027 27.70
2013 22.40 2028 23.90 2013 25.80 2028 27.80
2014 22.70 2029 24.20 2014 26.30 2029 28.30
- ---------------
* Results are expressed in real 2000 dollars.
5-9
256
LOW FUEL PRICE CASE. Typically the effect of the reduced oil and gas
prices is depressed energy prices as compared to the Base Case, which does occur
in the Low Fuel Price Case. For most years of the study, the decreased energy
prices were accompanied by increased compensation for capacity. This reflects
the relationship between the energy prices and compensation for capacity in our
methodology. A decline in energy prices tends to increase the capacity
contribution requirement. In 2000, the Low Fuel Price Case results in a
reduction in All-In prices of approximately 7%. This decrease is approximately
14% in 2003 through the end of the study period representing the increase
influence of gas and oil prices on the electricity prices in this region.
HIGH HYDRO CASE. The High Hydro Case results in All-In prices that are
lower than the Base Case. The increased hydro generation in the High Hydro Case
depresses prices by 5% to 12% in the first five years of the analysis. After the
assumed five years of high hydro conditions, the results are slightly different
than the Base Case reflecting the change in generic unit additions.
FIGURE 5-7
MONTANA ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[MONTANA ESTIMATED PRICE FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE
---------- -------- ---------
2000 24.1000 24.6900 26.6600
23.9000 24.6600 26.5000
2002 23.3000 24.2400 26.6300
24.6000 22.3000 26.0200
2004 24.4000 23.9800 26.9300
25.0000 21.4100 25.0200
2006 24.6000 21.4100 24.7400
24.8000 21.6400 24.8400
2008 25.2000 21.9000 25.4100
25.4000 22.1600 25.4800
2010 25.8000 22.3500 25.7100
25.3000 21.8600 25.2800
2012 25.5000 22.0900 25.5600
25.8000 22.4000 26.0600
2014 26.3000 22.6600 26.4100
25.9000 22.4500 25.9900
2016 25.7000 22.3700 25.7500
26.0000 22.4400 26.0100
2018 26.0000 22.4000 25.9600
26.4000 22.6915 26.3672
2020 26.3000 22.6949 26.3726
26.4000 22.6916 26.4144
2022 26.8000 23.0875 26.8339
27.0000 23.1586 26.9663
2024 27.1000 23.2425 27.1058
27.2000 23.2721 27.1555
2026 27.6000 23.6930 27.6342
27.7000 23.7000 27.6632
2028 27.8000 23.8996 27.8604
28.3000 24.2406 28.3290
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5.3.2 WASHINGTON OREGON EAST ENERGY AND ALL-IN PRICE FORECASTS SENSITIVITY CASES
The sensitivity cases energy price forecast and All-In price forecast for
Washington Oregon East are presented in Tables 5-8 and 5-9. A comparison of the
All-In prices for the Base Case, Low Fuel Price Case, and High Hydro Case is
illustrated in Figure 5-8.
TABLE 5-8
WASHINGTON OREGON EAST SENSITIVITY CASES ENERGY PRICE FORECASTS*
LOW FUEL PRICE ($/MWH) HIGH HYDRO ($/MWH)
- -------------------------- ---------------------------
2000 24.10 2015 21.70 2000 23.20 2015 25.40
2001 23.20 2016 21.30 2001 22.50 2016 25.00
2002 22.40 2017 21.30 2002 21.80 2017 25.10
2003 23.00 2018 20.90 2003 23.10 2018 24.60
2004 22.90 2019 20.60 2004 22.80 2019 24.30
2005 22.30 2020 20.70 2005 26.20 2020 24.20
2006 22.00 2021 20.50 2006 25.90 2021 24.10
2007 21.90 2022 20.40 2007 25.70 2022 24.00
2008 22.00 2023 20.10 2008 25.90 2023 23.70
2009 21.50 2024 19.70 2009 25.50 2024 23.20
2010 21.90 2025 20.00 2010 25.90 2025 23.40
2011 22.10 2026 19.90 2011 26.10 2026 23.40
2012 22.00 2027 19.90 2012 25.90 2027 23.50
2013 22.00 2028 20.50 2013 25.80 2028 24.10
2014 21.60 2029 20.70 2014 25.60 2029 24.40
- ---------------
* Results are expressed in real 2000 dollars.
TABLE 5-9
WASHINGTON OREGON EAST SENSITIVITY CASES ALL-IN PRICE FORECASTS*
LOW FUEL PRICE ($/MWH) HIGH HYDRO ($/MWH)
- -------------------------- ---------------------------
2000 27.10 2015 23.70 2000 26.70 2015 27.10
2001 26.80 2016 23.70 2001 26.30 2016 27.10
2002 26.00 2017 23.50 2002 25.30 2017 27.10
2003 24.10 2018 23.50 2003 26.60 2018 27.10
2004 25.60 2019 23.50 2004 26.30 2019 27.20
2005 23.40 2020 23.50 2005 27.10 2020 27.20
2006 23.20 2021 23.50 2006 26.50 2021 27.20
2007 23.20 2022 23.50 2007 26.50 2022 27.20
2008 23.30 2023 23.50 2008 26.70 2023 27.20
2009 23.40 2024 23.50 2009 26.70 2024 27.20
2010 23.40 2025 23.50 2010 26.90 2025 27.20
2011 23.50 2026 23.60 2011 27.00 2026 27.30
2012 23.50 2027 23.50 2012 27.00 2027 27.30
2013 23.60 2028 23.70 2013 27.00 2028 27.40
2014 23.90 2029 23.70 2014 27.60 2029 27.50
- ---------------
* Results are expressed in real 2000 dollars.
5-11
258
LOW FUEL PRICE CASE. In the 2000, the Low Fuel Price Case results in a
decrease in All-In prices of approximately 8%. The decrease is approximately 14%
in 2003 through the end of the study period.
HIGH HYDRO CASE. The High Hydro Case decreases prices by 5% to 11% in the
first five years of the analysis. The results are approximately the same as the
Base Case for the rest of the study period.
FIGURE 5-8
WASHINGTON OREGON EAST ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[WASHINGTON OREGON EAST ESTIMATED PRICE FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE
---------- -------- ---------
2000 26.7000 27.1000 29.3300
26.3000 26.8400 28.8800
2002 25.3000 25.9600 28.5300
26.6000 24.1000 27.9800
2004 26.3000 25.5600 28.7000
27.1000 23.3500 27.1400
2006 26.5000 23.1900 26.6400
26.5000 23.2000 26.5200
2008 26.7000 23.3300 26.9200
26.7000 23.3500 26.7600
2010 26.9000 23.4200 26.8700
27.0000 23.4700 26.9800
2012 27.0000 23.4900 27.0200
27.0000 23.6300 27.3200
2014 27.6000 23.8700 27.7000
27.1000 23.6600 27.2600
2016 27.1000 23.6500 27.1100
27.1000 23.5200 27.1100
2018 27.1000 23.4800 27.0800
27.2000 23.5315 27.2072
2020 27.2000 23.5049 27.1826
27.2000 23.4916 27.1744
2022 27.2000 23.5375 27.2239
27.2000 23.4586 27.1763
2024 27.2000 23.4725 27.1858
27.2000 23.4721 27.2155
2026 27.3000 23.5530 27.3242
27.3000 23.5100 27.2932
2028 27.4000 23.6896 27.5104
27.5000 23.6706 27.5290
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5.3.3 WASHINGTON OREGON WEST ENERGY AND ALL-IN PRICE FORECASTS SENSITIVITY CASES
The sensitivity cases energy price forecast and All-In price forecast for
Washington Oregon West are presented in Tables 5-10 and 5-11. A comparison of
the All-In prices for the Base Case, Low Fuel Price Case, and High Hydro Case is
illustrated in Figure 5-9.
TABLE 5-10
WASHINGTON OREGON WEST SENSITIVITY CASES ENERGY PRICE FORECASTS*
LOW FUEL PRICE ($/MWH) HIGH HYDRO ($/MWH)
- -------------------------- ---------------------------
2000 24.50 2015 22.10 2000 23.60 2015 25.90
2001 23.70 2016 21.70 2001 22.90 2016 25.40
2002 22.90 2017 21.70 2002 22.20 2017 25.50
2003 23.50 2018 21.30 2003 23.50 2018 24.90
2004 23.40 2019 20.90 2004 23.20 2019 24.50
2005 22.70 2020 21.00 2005 26.70 2020 24.50
2006 22.40 2021 20.90 2006 26.40 2021 24.50
2007 22.40 2022 20.70 2007 26.20 2022 24.30
2008 22.40 2023 20.50 2008 26.40 2023 24.00
2009 22.00 2024 20.00 2009 25.90 2024 23.50
2010 22.30 2025 20.30 2010 26.40 2025 23.80
2011 22.50 2026 20.10 2011 26.50 2026 23.60
2012 22.40 2027 20.20 2012 26.40 2027 23.70
2013 22.40 2028 20.70 2013 26.20 2028 24.30
2014 22.00 2029 20.90 2014 26.10 2029 24.60
- ---------------
* Results are expressed in real 2000 dollars.
TABLE 5-11
WASHINGTON OREGON WEST SENSITIVITY CASES ALL-IN PRICE FORECASTS*
LOW FUEL ($/MWH) HIGH HYDRO ($/MWH)
- -------------------------- ---------------------------
2000 27.60 2015 24.00 2000 27.10 2015 27.60
2001 27.30 2016 24.00 2001 26.70 2016 27.50
2002 26.40 2017 23.90 2002 25.70 2017 27.50
2003 24.60 2018 23.80 2003 27.00 2018 27.50
2004 26.00 2019 23.80 2004 26.70 2019 27.50
2005 23.80 2020 23.80 2005 27.70 2020 27.50
2006 23.60 2021 23.80 2006 27.10 2021 27.50
2007 23.60 2022 23.90 2007 27.00 2022 27.50
2008 23.80 2023 23.80 2008 27.20 2023 27.50
2009 23.80 2024 23.80 2009 27.20 2024 27.50
2010 23.80 2025 23.80 2010 27.40 2025 27.60
2011 23.90 2026 23.80 2011 27.40 2026 27.50
2012 23.90 2027 23.80 2012 27.40 2027 27.50
2013 24.00 2028 24.00 2013 27.50 2028 27.70
2014 24.30 2029 23.90 2014 28.00 2029 27.70
- ---------------
* Results are expressed in real 2000 dollars.
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LOW FUEL PRICE CASE. The All-In prices in the Low Fuel Case are
approximately 8%-9% lower in the first few years. From 2003 through the end of
the study period the results are approximately 14% lower. This reflects the
increased influence that gas and oil prices have on the market prices.
HIGH HYDRO CASE. The high hydro generation in the High Hydro Case
depresses prices in the first years of the study by 5% to 11%. After 2004, the
results are approximately the same as the Base Case.
FIGURE 5-9
WASHINGTON OREGON WEST ESTIMATED ALL-IN PRICE FORECAST ($/MWH)
[WASHINGTON OREGON WEST ESTIMATED PRICE FORECAST GRAPH]
HIGH HYDRO LOW FUEL BASE CASE
---------- -------- ---------
2000 27.1000 27.5700 29.8600
26.7000 27.3000 29.4000
2002 25.7000 26.4100 29.0400
27.0000 24.5600 28.5200
2004 26.7000 26.0200 29.2400
27.7000 23.8000 27.6600
2006 27.1000 23.6200 27.1500
27.0000 23.6400 27.0900
2008 27.2000 23.7700 27.4200
27.2000 23.7600 27.2000
2010 27.4000 23.8300 27.3300
27.4000 23.8800 27.4300
2012 27.4000 23.9000 27.4700
27.5000 24.0400 27.7600
2014 28.0000 24.2700 28.1400
27.6000 24.0600 27.7100
2016 27.5000 24.0400 27.5400
27.5000 23.8900 27.5000
2018 27.5000 23.8300 27.4400
27.5000 23.8215 27.4972
2020 27.5000 23.8049 27.4826
27.5000 23.8116 27.5144
2022 27.5000 23.8475 27.5439
27.5000 23.7786 27.5163
2024 27.5000 23.7725 27.4858
27.6000 23.7921 27.5655
2026 27.5000 23.7830 27.5442
27.5000 23.7700 27.5432
2028 27.7000 23.9596 27.7804
27.7000 23.9406 27.7990
5-14
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APPENDIX A
REGIONAL COAL PRICE FORECASTS
A.1 WSCC REGIONAL COAL PRICING
A summary of PHB Hagler Bailly's methodology for projecting pricing for
Powder River Basin; Utah, Colorado, and non-PRB Wyoming; New Mexico, Arizona,
and Colorado Raton; Lignite; and Western Canadian coal is presented below.
POWDER RIVER BASIN. PHB Hagler Bailly projects the use of three general
types of PRB coal in these regions during the study period. A low-Btu coal,
projected at 8,400 Btu per pound, a high-Btu coal, projected at 8,800 Btu per
pound, and a Montana PRB coal, at 9,000 Btu per pound. PHB Hagler Bailly
projected the FOB mine price of high-Btu PRB coal to increase slightly in real
terms to 2000, and then to decline gradually throughout the forecast period. A
near-term price increase is expected due to increasing demand as new,
higher-cost reserves begin to be exploited. Productivity gains were projected to
more than counterbalance growing demand after 2000, resulting in a real price
decrease trend of approximately 1% per year.
The price of low-Btu PRB coal was projected to be equivalent to the price
of high-Btu PRB coal on a delivered cost basis, in markets at the eastern edge
of PRB coal's market reach. Because the low-Btu coal suffers from higher
energy-equivalent transportation costs, the spot FOB mine price of the low-Btu
coal was projected to be lower than the (energy-adjusted) price of high-Btu
coal. In addition, the low-Btu coal is higher in sulfur, putting downward
pressure on prices as the value of sulfur dioxide emission allowances increases.
The rate of decrease in price is greater for this coal than for the high-Btu
coal.
The Montana PRB coal has a relatively limited market. Its price was
projected to retain a modest premium over high-Btu PRB coal during the forecast
period.
UTAH, COLORADO, AND NON-PRB WYOMING. Four coals were projected for use in
the WSCC in this group: a Utah coal, Northern and Western Colorado coals, and
coal from Wyoming's Hanna Basin. Each of these types of coal is projected to
follow the general projected trend of productivity-driven price decreases. As
productivity gains are reflected in market pricing, these coals are projected to
decrease in price (in real terms) at a rate of 2% per year throughout the
forecast period.
NEW MEXICO, ARIZONA, AND COLORADO RATON. Virtually all coal sold from New
Mexico and Arizona sources is sold under long-term contract to electric power
generators. Suppliers have virtually no other market for their coal, and
generators have virtually no other source of supply. When power market prices
are lower, suppliers have an incentive to sell coal at prices that maintain
generators' competitiveness in those markets. If generators cannot sell their
power they will not purchase coal during lower-price periods and suppliers will
suffer. This kind of cooperative pricing is consistent with what PHB Hagler
Bailly has observed in the southwestern market. For modeling purposes, PHB
Hagler Bailly projected a proxy coal price of $15 per ton, held flat in real
terms during the forecast period. This price is designed to represent a minimum
acceptable price for suppliers.
Raton Basin coal is sold in limited quantities to small, local generators,
and its price, projected at the same level as other Southwestern coals, is not
projected to decline in real terms during the forecast period.
LIGNITE. A few WSCC plants in the Northern Plains burn lignite from local
sources. Typically sold under long-term contract, Northern Plains lignite prices
are projected to remain flat in real terms throughout the forecast period.
WESTERN CANADIAN. Prices were projected for several mine-mouth-generating
stations in the Canadian sub-region of the WSCC. Prices were estimated by
analogy with similar coals in the Western United States, with a premium added to
correspond with the long-term contracting often characteristic of mine-mouth
facilities. Prices were projected to remain flat in real terms.
A-1
262
A.2 WSCC COAL TRANSPORTATION COSTS
PHB Hagler Bailly estimated all transportation costs using publicly
available data sources that provide information on electric utility delivered
fuel costs and commercial publications providing spot coal market pricing. PHB
Hagler Bailly developed transportation cost estimates for particular coal types
delivered to specific plants, based on spot coal purchases, to reflect marginal
delivered pricing. Transportation costs for coal types not historically used at
a particular location were based on industry experience and economic analysis.
RAIL. PHB Hagler Bailly projects western rail rates, applicable to WSCC
coals, to decline in real terms. With continued productivity gains, continued
competition between the Burlington Northern Santa Fe Railroad and the Union
Pacific Railroad, and the construction of the proposed Dakota, Minnesota, and
Eastern Railroad, rail rates are projected to decline at 2.5% per year in real
terms through 2010, for generating plants with access to more than one rail
carrier. Thereafter, PHB Hagler Bailly projects decreases to continue at a
slower rate of 1% per year. For plants without competitive access, rail rates
are projected to remain flat in real terms.
TRUCK. Truck rates are projected to decline slowly during the forecast
period, at a rate of 0.1% per year in real terms, to reflect small capital
improvements in an industry that is already very competitive.
A-2
263
APPENDIX B
TRANSFER CAPABILITY
The transmission system is the transportation mechanism that moves power
from where it is generated to where it is to be used. There are a number of
technical factors that limit the amount of power between utilities, control
areas or large regions. While facility ratings are one key element, voltage
levels or instability are other considerations that need to be considered in
establishing transfer capabilities. In addition, transfers that involve two
utilities or control areas will have an impact on the transfer capabilities of
neighboring utilities because a portion of that transfer will flow on
neighboring utilities' lines. In order to quantify transmission capabilities
between NERC regions and major subregions, seasonal analyses are performed that
include current operating parameters, load patterns and scheduled transfers to
determine regional import and export capabilities.
The transfer capabilities that are shown are non-simultaneous, meaning that
for any given transfer at an identified limit, the other transfer limitations
shown in the tables are unlikely to be attainable at the same time. Concurrent
exports or imports for any particular region may not be technically feasible at
the total of the capabilities listed. These values represent the ability of the
transmission networks to accommodate the transfer electricity from one area to
another area for a single load and generation pattern. Therefore, the actual
patterns of demands and generation can result in changes in transfer
capabilities on both an hourly and daily basis. These transfer capabilities have
been considered as representative of the level of interchange that could occur
between the various transmission areas. The following highlights some of the
issues associated with the bulk transfer capabilities between regions and
subregions that have been included in the study.
B.1 WSCC
The transmission path between Wyoming and Colorado is often heavily loaded
and requires operating procedures to be implemented to provide loading relief
for this path in the winter.
While the northwest (Washington and Oregon) is a net exporter of power in
the winter in good water years, the region can be dependent upon imported power
under some contingencies such as during extreme cold weather. Import transfer
capability at California-Oregon Intertie (COI), which is normally at 3,675 MW
(winter), can be limited to 1,350 at extreme levels of demand in Washington and
Oregon. Additionally, the import capability of B.C. Hydro to the northwest
United States is reduced from 3,150 MW when imports on COI exceed 1,200 MW and
imports on the Pacific DC Intertie exceed 2,430 MW. The maximum simultaneous
import capability for the Northwest is 10,900 MW in the winter.
The completion of the Crystal to Allen 230-kV line in southern Nevada will
connect Nevada Power Company with the McCullough -- Navajo line and allow for
greater imports into southern Nevada from either southern California or Arizona.
Phase-shifting transformers in southern Utah-Colorado-Nevada transmission system
are available to control unscheduled flows and maintain regional transfers
within facility ratings.
TABLE B-1
WSCC TRANSMISSION TRANSFER CAPABILITY
WINTER SUMMER
CAPABILITY CAPABILITY
FROM TO (MW) (MW)
- ---- ---------------- ---------- ----------
Alberta British Columbia 1,000 1,000
Arizona New Mexico 1,501 1,501
Arizona So. California 2,517 2,517
Arizona Southern Nev 2,517 2,517
Arizona Utah 850 850
B-1
264
WINTER SUMMER
CAPABILITY CAPABILITY
FROM TO (MW) (MW)
- ---- ---------------- ---------- ----------
British Alberta
Columbia 1,200 1,200
British E. Northwest
Columbia 400 400
British W. Northwest
Columbia 2,850 2,850
CFE So. California 408 408
Colorado New Mexico 600 600
Colorado Utah 550 550
Colorado Wyoming 1,424 1,424
E. Northwest British Columbia 400 400
E. Northwest Idaho 1,200 1,200
E. Northwest Montana 600 600
E. Northwest No. California 4,800 4,800
E. Northwest So. California 2,876(1) 2,876(1)
E. Northwest W. Northwest 14,653 14,653
Idaho E. Northwest 2,400 2,400
Idaho Montana 337 337
Idaho Sierra Pacific 500 500
Idaho Utah 1,500 1,500
Montana Idaho 337 337
Montana Wyoming 400 400
Montana E. Northwest 2,200 2,200
New Mexico Arizona 2,517 2,517
New Mexico Colorado 600 600
No. California E. Northwest 3,675 3,675
No. California Sierra Pacific 160 160
No. California So. California 3,000 3,000
No. California W. Northwest 30 30
Sierra Pacific Idaho 360 360
Sierra Pacific No. California 160 160
Sierra Pacific Utah 245 245
So. California Arizona 2,750 2,750
So. California CFE 408 408
So. California E. Northwest 2,858 2,858
So. California No. California 3,000 3,000
So. California Southern Nevada 6,600 6,600
So. California Utah 1,400 1,400
Southern Nevada Arizona 2,517 2,517
Southern Nevada So. California 6,600 6,600
Southern Nevada Utah 300 300
Utah Arizona 820 820
Utah Colorado 550 550
Utah Idaho 1,000 1,000
Utah Sierra Pacific 245 245
Utah Southern Nevada 300 300
Utah Wyoming 420 420
Utah So. California 1,920 1,920
W. Northwest British Columbia 2,000 2,000
B-2
265
WINTER SUMMER
CAPABILITY CAPABILITY
FROM TO (MW) (MW)
- ---- ---------------- ---------- ----------
W. Northwest E. Northwest 16,500 16,500
W. Northwest No. California 100 100
Wyoming Colorado 1,424 1,424
Wyoming Idaho 2,200 2,200
Wyoming Montana 400 400
Wyoming Utah 400 400
- ---------------
(1) Capacity increases to 2,990 MW in 2011.
(2) Capacity decreases to 635 MW in 2011.
B-3
266
APPENDIX C
NEW CAPACITY ADDITIONS
For the first three years of the study period (2000-2002), identified
merchant plant projects are added to the system based on the estimated on-line
date of the project (see Table 4-11). After this initial period, the market
entry and exit logic determines the amount and timing of new generation capacity
added to the system as well as the retirement of existing units. Starting in
2003, the market entry and exit logic, at a minimum, builds enough new capacity
to meet the estimated reserve requirements.
The following table describes the timing and amount of market entry and
exit (retirements) for the Base Case for the Northwest.
TABLE C-1
CUMULATIVE CAPACITY ADDITIONS IN THE NORTHWEST
CUMULATIVE
COMBINED CYCLE COMBUSTION CAPACITY
PLANTS ADDED TURBINES ADDED RETIREMENTS ADDITIONS
YEAR (MW) (MW) (MW) (MW)
- ---- -------------- -------------- ----------- ----------
2001 38 -38
2002 992 954
2003 2276 3230
2004 3230
2005 1,040 1,170 3100
2006 1,040 4140
2007 520 4660
2008 4660
2009 1,040 5700
2010 5700
2011 520 6220
2012 6220
2013 6220
2014 6220
2015 520 6740
2016 1,040 7780
2017 520 8300
2018 520 8820
2019 520 8 9332
2020 9332
2021 520 66 9786
2022 520 75 10231
2023 520 10751
2024 520 70 11201
2025 100 11101
2026 1,040 12141
2027 520 105 12556
2028 12556
2029 520 13076
------ --- ----- -----
TOTAL 14,708 0 1,632 13076
====== === ===== =====
C-1
267
APPENDIX D
SUPPLY CURVES
The supply curves provided in this appendix provide a summary of the
projected installed capacity in the Northwest market for 2003 and 2015 sorted by
dispatch price. The dispatch price is based on the average annual marginal
dispatch cost of the units and does not include additional capacity
compensation. As shown in the charts, PPL Montana's assets are identified on the
lower portion of the curve.
The first set of supply curves provides a summary of all of the installed
resources in the region including hydro capacity. The second set of supply
curves provides a summary of the projected installed thermal resources in the
region by type of fuel.
NORTHWEST CAPACITY MARKET EFFECTIVE SUPPLY CURVE 2003
ALL UNITS
[SUPPLY CURVE 2003 ALL UNITS GRAPH]
D-1
268
NORTHWEST CAPACITY MARKET EFFECTIVE SUPPLY CURVE 2015
ALL UNITS
[SUPPLY CURVE 2015 ALL UNITS GRAPH]
NORTHWEST CAPACITY MARKET EFFECTIVE SUPPLY CURVE 2003
THERMAL UNITS
[SUPPLY CURVE 2003 THERMAL UNITS GRAPH]
D-2
269
NORTHWEST CAPACITY MARKET EFFECTIVE SUPPLY CURVE 2015
THERMAL UNITS
[SUPPLY CURVE 2015 THERMAL UNITS GRAPH]
D-3
270
APPENDIX C: INDEPENDENT FUEL CONSULTANT'S REPORT
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271
DUE DILIGENCE FUEL SUPPLY REVIEW
COLSTRIP AND CORETTE
GENERATING STATIONS
MONTANA
Prepared For
CHASE SECURITIES INC.
By
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
Denver, Colorado
[John T. Boyd LOGO]
Report No. 2817.002
JUNE 22, 2000
C-2
272
[John T. Boyd LOGO]
June 22, 2000
File: 2817.002
Chase Securities, Inc., on behalf of the initial purchasers
Subject: Fuel Supply Review -- Colstrip and Corette Generating Stations
Dear Sirs:
This letter updates John T. Boyd Company's (BOYD) 1999 review of fuel
supplies to the coal-fired Colstrip and Corette Generating Stations located in
southeastern Montana. PPL Montana LLC (PPL) recently acquired a partial interest
in the 2094 net MW Colstrip Station, and full ownership of the 154 net MW
Corette Station as part of a larger purchase of generation and transmission
assets from Montana Power Company.
BOYD was retained by Chase Securities, Inc., in December 1998 to conduct
due diligence investigations of fuel supplies for the generating stations,
addressing long-term availability and delivered cost of coal. A report on that
investigation, entitled "Due Diligence Fuel Supply Review: Colstrip and Corette
Generating Stations" was issued in March 1999. A comprehensive update of that
report was provided in September 1999 and is attached herewith. The primary
findings of the September update were essentially unchanged from the March
study. This current letter update supplements these previous reports, and is
subject to the conditions and limitations noted in those documents. This review
does not constitute and is not intended as a comprehensive due diligence study.
We have accepted the information provided for our review as accurate and
complete.
Our update addresses various issues and changes in circumstances that have
been identified or have occurred since the earlier reports were issued. It is
based on an on-site inspection of the Rosebud Mine (which provides fuel to
Colstrip), discussions with engineering and operations personnel, and a review
of geologic and mine planning documents. The Corette Station fuel supply was
discussed with appropriate personnel, and relevant documents were reviewed.
SUMMARY
Our review and update indicates that the fundamental conclusions reached in
our March and September 1999 reports regarding long-term fuel supplies continue
to be reasonable and valid as of this date. Major conclusions are briefly
restated below:
- There are adequate proven and probable coal reserves available to satisfy
current contractual commitments to the Colstrip station, and the Rosebud
Mine reserves and resources (beyond those currently committed) are
adequate to fuel the station through year 2030. WECO's property ownership
is such that all reserves are effectively controlled.
- Coal reserve quality is well-defined (proven and probable), meets
contract specifications, and is similar to that currently burned at the
Colstrip Station.
- The mine is permitted and generally in compliance with applicable laws
and regulations. No environmental "fatal flaws" were found relative to
current and future operations.
- The Rosebud mining equipment and facilities are functional and
appropriate for planned operations. Capital additions/commitments since
our 1999 review have upgraded the capability and reliability of the
equipment fleet.
C-3
273
- Current mining plans are reasonable and consistent with the "least-cost"
mining approach. No factors or circumstances were identified which would
require a material change in future mining plans and cost projections.
- Our update did not identify any circumstances or issues that would
require revisions to the Colstrip fuel cost projections presented in our
1999 reports. In BOYD's opinion, those fuel cost projections remain
reasonable and valid.
- The Corette plant obtains fuel from the large mines in the Southern
Powder River Basin (SPRB) under short-term agreement. The SPRB will
continue to be a viable coal source for Corette. Actual delivered fuel
cost in 2000 exceeds our projections by approximately 11% due to
higher-than-anticipated rail rates. We believe, however, that over the
long term, rail rates can be reduced to levels reflected in our 1999
projections. Thus, in BOYD's opinion, the long-term fuel cost projections
for Corette presented in our 1999 reports remain reasonable and valid.
These updated conclusions supplement BOYD's March and September 1999 reports.
These and other issues are addressed in greater detail in those reports.
COLSTRIP GENERATING STATION FUEL SUPPLY
The Colstrip Generating Station draws its coal supply from Western Energy
Company's (WECO) nearby Rosebud Mine. Coal is purchased under two long-term
agreements, one for fuel to Units 1 & 2, the other for Units 3 & 4. In addition,
Rosebud Mine produces coal and waste coal product for third party customers.
These sales are summarized:
TYPICAL
MINE PRODUCTION
AREA CUSTOMER (TONS/YEAR-000)
- ---- -------- ---------------
A Third Party Customers 2,000
B Colstrip Units 3 & 4 6,500
C Colstrip Units 1 & 2 2,900
BOYD personnel visited the Rosebud Mine in April 2000, reviewed future
mining plans and projections, and discussed ongoing operations with WECO
personnel. Issues addressed included:
- LAND CONTROL. Federally owned coal reserves in Area C (Sections 6 and
32) that were not controlled at the time of our March 1999 report have
been successfully leased and are scheduled for mining within the next two
years. The other remaining land issue relates to surface damages on the
Kluver Tract in Area D. Although the issue of surface damages is
unresolved, WECO has full mining rights to the coal on these properties.
Any delays in negotiating the damage payments should not materially
affect mining in Area D.
- EXPLORATION AND RESERVE ESTIMATES. During 1999, WECO conducted a
drilling and sampling program in Area C and to a lesser extent in Area D.
The holes drilled were primarily for "in-fill" purposes, and generally
confirmed previous information. Some additional proven reserves were
identified as a result of the program, and approximately four million
tons in Area C-North have been incorporated into the mine plan. Areas
were also identified where the seam can be selectively loaded (avoiding a
parting), which may result in minor reserve losses.
- ENVIRONMENTAL/PERMITTING ISSUES. Permitting of the recently leased
federal tracts (Sections 6 and 32) is complete. Montana DEQ and OSM
indicated some concern with the length of opened highwall in idled mine
areas. (The situation is attributable to the "least-cost" mining approach
required in the Units 3 & 4 contract.) WECO has scheduled some pit
backfilling, grading, and reclamation in 2000 and 2001, which should
alleviate the concerns of DEQ and OSM. The cost of this reclamation
should not impact coal price.
- MINING OPERATIONS. WECO is presently producing from Areas B, D, and
C-South at the Rosebud Mine. Areas C and D have been active for some
time. Area B was idle at the time of BOYD's
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January 1999 site visit, but has since been restarted. Mining methods,
equipment applications, and operating practices are essentially unchanged
since our earlier report.
- OUTSIDE SALES. In July 1999, WECO began mining in Area B to supply
approximately 1.5 million tons per year (MTPY) of coal to Minnesota Power
Company and other small customers. WECO's long-term mining plans (and
those addressed in our 1999 reports) do not consider these additional
outside sales. While incorporating this tonnage could have some effect on
future mining costs, we believe any impacts on the Colstrip price under
current contracts will be minimal.
- MINE PLANNING/FUTURE OPERATIONS. WECO has not made significant changes
to long-range plans since our earlier work. They have incorporated minor
sequencing and optimization changes, as is normal in the course of mine
planning efforts. As discussed above, mine plans have not been modified
to incorporate outside sales. We do not anticipate that either the minor
changes which have been made or incorporating outside sales would
appreciably impact projected fuel costs to Colstrip. Our review did not
identify any circumstances that would require major changes to the 1999
long-range plan.
The Units 3 & 4 contract incorporates a "least-cost" planning approach
and requires a mine operating committee to approve the mine plan and
budget. This approval process has been slow, and while it should improve
over time, regular long-range cost forecasts have not been finalized. Our
inspection of the mine, review of planning information, and discussions
with mine personnel did not identify or disclose any circumstances which
would engender a major revision to the existing long-range plan. However,
there may be potential to make minor adjustments to the "least-cost"
approach, resulting in lower overall fuel costs.
- CAPITAL EXPENDITURES. WECO has budgeted and/or spent substantial capital
for equipment replacements, major repairs, and mine infrastructure since
our 1999 study. BOYD previously expressed concern regarding the advanced
age of the equipment and the capital expenditures needed in the near term
to maintain productive capability. WECO management is cognizant of this
and has budgeted and/or completed the following recent purchases:
-- Three Kress 200-ton coal trucks are scheduled for delivery in July,
August, and September 2000. These are replacements for some of the
Dart 160-ton trucks in Area C.
-- In late 1999, two large dozers were purchased for Area C, and in
April 2000, a third large dozer was delivered to Area D.
-- Two 20,000-gallon water wagons are being purchased to replace three
older and smaller-capacity units.
-- A new 60-cy class bucket for the Marion 8050 draglines is on order.
-- A replacement tub is being fabricated for the Marion 8200 dragline.
The tub replacement project is budgeted at $4.35 million.
Total capital expenditures for 2000 are budgeted at $17.6 million. This is
slightly below estimates in BOYD's previous fuel supply report, but is
adequate to maintain the productive capability of the mine. Additional
monies are budgeted for capital replacements in future years.
These issues and changes from the circumstances reflected in our 1999 due
diligence reviews are generally consistent with projections in those reviews, or
are relatively minor in nature. To the extent such changes would impact
projections of future fuel prices, that impact would be limited and within the
range of accuracy for such projections. Thus, in our opinion, the fuel price
projections presented in our 1999 reports remain valid as of this date.
CORETTE GENERATING STATION FUEL SUPPLY
The Corette Station is fueled by coal from commercial mines in the southern
portion of the Powder River Basin (SPRB). At the time of our 1999 reviews, this
coal was purchased from Peabody Holding Company's
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275
Rawhide and North Antelope Mines, and delivered to Corette via the Burlington
Northern -- Santa Fe Railway (BNSF). These purchase and transportation
agreements expired in 1999.
Following negotiations with suppliers and the BNSF in 1999, PPL secured new
coal supplies and negotiated a short-term transportation agreement. Currently,
Corette receives coal from RAG Coal West, Inc.'s Eagle Butte Mine and Decker
Coal Company's Decker Mine. These contracts are one-year agreements, extending
through December 31, 2000. Key contract terms are:
RAG COAL
WEST DECKER
---------- ----------
Annual Quantity (Tons-000).................................. 450 - 750 100 - 200
Coal Quality:
Heat Content (Btu/Lb.).................................... 8,200 9,200 min.
min.......
Sulfur Content (Lbs.SO(2)/MMBtu).......................... 0.7 max... 0.7 max.
Ash Content (Lbs./MMBtu).................................. 6.4 max... 6.0 max.
Moisture (%-A.R.) 32.5 max.. 28.0 max.
Price ($/Ton) -- FOB Mine................................... 4.20 7.25
The coal price negotiated for the bulk of the tonnage, $4.20/ton from Eagle
Butte, is consistent with our 1999 projections. The price of Decker coal, at
$7.25/ton for a 9,200-Btu/lb. product is above projections, on both a per-ton
and $/MMBtu basis. PPL indicates that the higher quality Decker coal results in
more efficient combustion in the boiler, and resulting savings are expected to
offset the higher fuel cost.
Coal is transported to the Corette Station by the BNSF under provisions of
a short-term agreement expiring June 30, 2000. Contract rail rates, and
resulting delivered price, are summarized:
RAG COAL
WEST DECKER
-------- ------
FOB Mine Price ($/Ton)...................................... 4.20 7.25
Rail Transportation ($/Ton)................................. 5.93 4.76
Delivered Price ($/Ton)..................................... 10.13 12.01
Delivered Price ($/MMBtu)................................... 61.8 65.3
The current short-term rail rates for deliveries to Corette are
approximately the same as were in effect in 1999. In the 1999 negotiations with
BNSF, PPL expected to achieve a reduction from the then-existing +/- $6.00/ton
rail rate. PPL was not, however, successful in obtaining such a reduction, and
instead opted for a short-term/tariff agreement extending for an indefinite
period beyond June 30, 2000, allowing for further bargaining. PPL is taking
steps to strengthen their position and is negotiating to obtain a rate reduction
in the near future.
Our review in 1999 indicated that the +/-- $6.00/ton rail rate was high,
and that a negotiated rate reduction was a strong possibility. We continue to be
of the opinion that such a reduction can be negotiated, and that PPL is pursuing
the matter appropriately. However, the rail rate projected for 2000 in our 1999
report is approximately 18% below the actual rate, and the resulting delivered
fuel cost projection is 11% below the actual fuel cost to Corette. We consider
this difference, which has a net impact of approximately $800,000 per year, to
be within the range of accuracy of the analysis, and believe that over the long
term, the actual rate can be lowered to levels projected in our 1999 study.
Thus, we consider the projections in our 1999 report reasonable as presented,
and do not believe any modifications are appropriate.
In BOYD's opinion, the large mines in the SPRB will continue to provide a
reliable long-term, low-cost fuel source for Corette.
SALE OF WESTERN ENERGY COMPANY
On March 28, 2000, Montana Power announced that it intends to divest its
coal mining subsidiaries. WECO is consequently being offered in a stock sale,
with that sale expected to be completed within 6 to
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276
12 months. Assuming a buyer has adequate financial resources, the sale of the
mine should have minimal impact on the cost of fuel to the Colstrip Station. In
the worst case, where WECO, under new ownership, defaults financially or
operationally, the Colstrip Station owners have multiple rights, including
taking over the mine operation. Since the mine operates essentially as a
stand-alone entity, this would not be expected to have a long-term adverse
effect on fuel supply or price. The Corette Station would not be affected by a
sale of Western Energy. Thus, we do not anticipate that the sale of WECO will
materially affect the fuel supply to the Colstrip or Corette Stations.
Respectfully submitted,
JOHN T. BOYD COMPANY
By:
/s/ /s/<WS>Lee<WS>A.<WS>Miller
------------------------------------
Lee A. Miller
Senior Mining Engineer
/s/ /s/<WS>Richard<WS>L.<WS>Bate
--------------------------------------
Richard L. Bate
Vice President
/s/ /s/<WS>Lawrence<WS>M.<WS>Thomas
--------------------------------------
Lawrence M. Thomas
Senior Vice President
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277
DUE DILIGENCE FUEL SUPPLY REVIEW
COLSTRIP AND CORETTE
GENERATING STATIONS
MONTANA
Prepared For
CHASE SECURITIES INC.
By
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
Denver, Colorado
[John T. Boyd LOGO]
Report No. 2817.002
SEPTEMBER 1999
278
TABLE OF CONTENTS
PAGE
----
TABLE OF CONTENTS
1.0 GENERAL STATEMENT.................................................. 1-1
Figure 1.1: General Location Map................................... 1-2
2.0 SUMMARIZED FINDINGS................................................ 2-1
3.0 GEOLOGY AND RESERVES............................................... 3-1
3.1 Introduction................................................ 3-1
3.2 Location and Access......................................... 3-1
3.3 Topography and Drainage..................................... 3-1
3.4 Property Ownership and Control.............................. 3-1
Figure 3.1: Coal Lease Map.................................. 3-3
3.5 Regional Geology............................................ 3-4
3.6 Local / Coal Geology........................................ 3-4
3.7 Exploration................................................. 3-4
Figure 3.2: Regional Map.................................... 3-5
Figure 3.3: Coal Zone Stratigraphic Section................. 3-6
3.8 Reserve Audit Procedures.................................... 3-7
3.9 Coal Reserves and Resources................................. 3-8
Figure 3.4: Mine Area Map -- Rosebud Mine................... 3-9
3.10 Coal Quality................................................ 3-12
Tables:
3.1 Coal Resource Summary -- Rosebud Mine................... 3-15
3.2 Coal Quality Summary -- Rosebud Mine.................... 3-16
4.0 ROSEBUD MINE....................................................... 4-1
4.1 Introduction................................................ 4-1
4.2 Present Mine................................................ 4-1
4.3 Coal Handling and Transportation............................ 4-4
4.4 Environmental and Permitting................................ 4-5
4.5 Mining Plans................................................ 4-6
279
PAGE
----
4.6 Cost Projections............................................ 4-9
4.7 General Comments............................................ 4-11
Tables:
4.1 Historical Performance Summary -- Rosebud Mine.......... 4-12
4.2 Mine Plan and Cost Estimate -- Units 1 & 2.............. 4-15
4.3 Mine Plan and Cost Estimate -- Units 3 & 4.............. 4-20
4.4 Conveyor Operating Cost Estimate........................ 4-25
5.0 ALTERNATIVE SUPPLIES............................................... 5-1
5.1 Introduction................................................ 5-1
5.2 Southern Powder River Basin................................. 5-1
5.3 Transportation.............................................. 5-3
5.4 Corette Station Fuel Supply................................. 5-4
5.5 Other Supply Sources........................................ 5-4
6.0 FUEL COSTS......................................................... 6-1
6.1 Introduction................................................ 6-1
6.2 Colstrip -- General......................................... 6-1
6.3 Colstrip Units 1 & 2........................................ 6-1
6.4 Colstrip Units 3 & 4........................................ 6-4
6.5 Colstrip -- Alternative Supply Potential.................... 6-7
6.6 Corette..................................................... 6-10
6.7 Fuel Price Estimates -- Inflated Basis...................... 6-12
Tables:
6.1 Estimated Fuel Price Summary -- 1998 Dollars............ 6-13
6.2 Estimated Fuel Price Summary -- Inflated Dollars........ 6-17
APPENDIX
A: Major Equipment List -- Rosebud Mine........................ A-1
280
GENERAL STATEMENT
PP&L Global, Inc., has agreed to acquire certain electric power generating
facilities in Montana, including the Corette Station, and a majority interest in
the Colstrip Station. The 163-MW Corette Station is located near Billings, while
the 2,276-MW Colstrip Station is located in Rosebud County in southeastern
Montana (see Figure 1.1 following this page). Both stations are coal fired.
Chase Securities, Inc., acting as financial advisor to PP&L Global, Inc.,
retained John T. Boyd Company (BOYD) in December 1998 to conduct a due diligence
investigation of the fuel (coal) supply for the Corette and Colstrip Stations. A
report on that investigation was issued in March 1999. This updated report
reflects changes from March 1999 through September 1999, and addresses certain
long-term fuel supply issues. BOYD is an internationally recognized mining and
geological consulting firm specializing in the coal industry, and is familiar
with current and potential future fuel sources for the stations.
The Colstrip Station operates four generating units, Units 1 & 2 rated at
333 MW each, and Units 3 & 4, rated at 805 MW each. All four units burn coal
produced by Western Energy Company (WECO) at the nearby Rosebud Mine. The mine
is configured as two separate operations, referred to as Area D and Area C, with
common management. Area D is adjacent to the plant and produces coal for Units 1
& 2. Area C, located 5 miles west of the plant, produces coal for Units 3 & 4,
which WECO transports via overland conveyor to the plant. Coal is purchased
under two long-term contracts, one for Units 1 & 2, the second for Units 3 & 4.
A third contract governs the conveyor operation.
The Corette Station is a single 163-MW unit which, until 1996, was also
fired by Rosebud Mine coal. In 1996, it was determined that coal from the large
mines in Wyoming's Southern Powder River Basin (SPRB) would be less expensive,
and fuel purchases were changed to that source. That coal is purchased under
short-term or spot agreements, which essentially reflect market price. The coal
is transported to Corette by the Burlington Northern-Santa Fe Railway (BNSF).
BOYD's due diligence study primarily addresses the availability of adequate
quantities and qualities of fuel for the plants over the period July 1, 1999,
through 2030. We reviewed the capability of WECO and SPRB producers to reliably
supply the coal, and the estimated delivered cost of the fuel from those
sources. The scope of our study considers that the subject fuel supply sources
have a proven track record as reliable long-term suppliers to the plants.
In conjunction with this updated report, we have reviewed, in general
terms, the potential fuel supply sources and delivery options extending through
2048.
1-1
281
[Rosebud Graphic Map]
1-2
282
Fuel cost estimates for the 1999 - 2030 period rely to a great extent on
interpretations regarding the pricing structure under current coal supply
agreements. We have made these interpretations and developed the estimates based
on our understanding of the agreements and assumptions regarding future events.
We do not intend to offer a legal interpretation of contract language, nor can
we reliably define the outcome of issues such as price re-openers.
The study period extends beyond the term of all of the current coal supply
agreements. We have made reasonable assumptions about extensions of those
agreements; however, there is no assurance that such extensions will be agreed
to. For this reason, we have assessed the availability of alternative fuel
sources such as the SPRB.
Our study is based on data received from WECO, PP&L Global, and Chase,
which we have accepted as accurate and complete. This data is supplemented by
publicly available information, our familiarity with the specific coal
properties, and knowledge of the industry in general. The available data as of
March 1999 is adequate and suitable as a basis for our study and conclusions as
defined herein. Updated information as of September 21, 1999, is based on
telephone conversations with WECO personnel which we have accepted as accurate
without verification. Specific projections of reserves, production, quality, and
costs included in this update have not been revised from our March 1999 report.
Although our review and update identified certain changes in circumstances since
March 1999 which could affect cost projections, we do not believe those changes
would substantially alter the findings of our original report. Unless noted
otherwise, all dollar amounts are in 1998 dollars with no allowance for
inflation.
This study is intended to conform to our proposal to Chase dated December
31, 1998, and the scope of work therein (as modified). The study is prepared in
accordance with accepted professional standards for such due diligence studies.
BOYD makes no other warranty, expressed or implied.
Respectfully submitted,
JOHN T. BOYD COMPANY
By:
/s/ Edward C. Mast /s/ Lee A. Miller
- ---------------------------------------------- ----------------------------------------------
Edward C. Mast Lee A. Miller
Senior Geologist Senior Mining Engineer
/s/ Richard L. Bate /s/ Lawrence M. Thomas
- ---------------------------------------------- ----------------------------------------------
Richard L. Bate Lawrence M. Thomas
Vice President Senior Vice President
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283
SUMMARIZED FINDINGS
The primary findings of John T. Boyd Company's (BOYD) due diligence review
of fuel supplies for the Colstrip and Corette Stations are summarized in this
chapter. These findings are supported by and expanded on in the balance of this
report.
1. The Colstrip Station is fueled by coal from Western Energy Company's
(WECO) Rosebud Mine in southeastern Montana. The Rosebud Mine is expected to
continue as the station's fuel source for the duration of the current Coal
Supply Agreements, and possibly beyond.
The Corette Station is fueled by coal purchased under short-term agreements
from mines in Wyoming's southern Powder River Basin (SPRB). The SPRB will likely
continue as Corette's fuel source over the long term.
2. WECO estimated the quantity and quality of proven and probable coal
reserves available at the Rosebud Mine. These estimates were reviewed by BOYD,
and, based on that review, it is our opinion that there are adequate reserves
available to satisfy current contractual commitments to the Colstrip Station.
Our review also indicates that:
- WECO's reserve estimates are based on sufficient exploration data to be
considered proven (over 95% of total tonnage) and probable, and are
developed using techniques and parameters accepted in the industry.
- Estimated proven and probable reserves remaining on the Rosebud property
total approximately 300 million recoverable tons divided into five
geographic areas:
REMAINING
RECOVERABLE
AREA STATUS TONS (000)
- ---- ------ -----------
Assigned Reserves:*
Area C Active -- Dedicated to Units 3 & 4 142,228
Area D Active -- Dedicated to Units 1 & 2 40,211
-------
Subtotal 182,439
Supplemental Reserves:
Area A Inactive -- Partially depleted 9,400
Area B Inactive -- Partially depleted 25,600
Area F Unmined 79,900
-------
Subtotal 114,900
Total 297,339
- ---------------
* Dedicated to Colstrip Station under current contracts.
The assigned reserves in Areas D and C are adequate to meet commitments
under the existing contracts at estimated station consumption levels.
- WECO's property ownership is such that all reserves are effectively
controlled.
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284
- Coal quality is well defined. Product quality depends on selective mining
techniques to control ash and sulfur, which are proven effective and a
normal part of WECO's ongoing operation. Estimated product coal quality
is:
AS-RECEIVED BASIS
---------------------------------
MOISTURE ASH SULFUR NA(2)O
AREA (%) (%) BTU/LB (%) (% IN ASH)
- ---- -------- ---- ------ ------ ----------
Assigned Reserves:
Area C................................. 25.97 9.32 8,509 0.68 0.49
Area D................................. 26.83 7.95 8,558 0.62 0.58
----- ---- ----- ---- ----
26.16 9.02 8,520 0.67 0.51
Supplemental Reserves:................. 25.36 8.74 8,634 0.75 0.84
This coal quality meets contract specifications and is similar to that
currently burned at the Colstrip Station.
- Although WECO is not obligated to make additional reserves available
after expiration of the existing contracts (2009 for Units 1 & 2, and
2019 for Units 3 & 4), we consider it reasonably likely that WECO will do
so. Substantial reserves are available to support such an extension.
3. The Rosebud Mine has historically been a stable, reliable supplier to
the Colstrip Station, and the mine can be expected to continue to perform
reliably. Our review of the mine operation indicates:
- The mine equipment and facilities are appropriate for planned operations
with some over-capacity. Much of the equipment is relatively old and will
require replacement or major maintenance in the near future. The cost of
these replacements and/or major maintenance is included in fuel price
estimates herein.
- Salaried and hourly personnel are experienced and adequately skilled.
Hourly workers are represented by the International Union of Operating
Engineers under a collective bargaining agreement expiring in 2001. Labor
relations historically have not been contentious.
- The mine has recently taken steps to reduce costs, significantly lowering
operating costs as a result.
- The mine is fully permitted and generally in compliance with applicable
laws and regulations. No environmental "fatal flaws" were found relative
to current and future operations. Permit modification efforts necessary
to conform with current mining plans are underway.
4. WECO has developed mining plans (as of January 1999) for Rosebud
covering the term of the current Colstrip contracts. BOYD reviewed these plans
and extended them through the full study period (i.e., 2030). Our findings
relative to future plans are:
- WECO has adopted a "least cost" mining approach. This will result in
relatively low costs initially, followed by gradually increasing costs
over the mine life.
- WECO's mining plans are reasonable and consistent with the "least cost"
mining approach. Delays in leasing certain federal coal properties have
resulted in minor variations from the plan; however, these variations do
not impair the long-term viability of the plan.
- WECO projects continued use of existing equipment, methods, and
techniques, with replacements and upgrades as appropriate. We consider
this a reasonable assumption.
- WECO's plans are based on lower (+/-5%) production rates than required to
meet projected station generation levels. BOYD has therefore accelerated
and extended WECO's basic plans for purposes of this study. Key
assumptions in this modified plan are:
Plan Period: 1999 - 2030
Mine Production: 10.1 MTPY
Required Coal: 319 Million Tons
2-2
285
Units 1 & 2
Areas Mined: D, B, A
Production: 3.0 MTPY
Avg. Eff. Ratio: 7.0 BCY/Ton
Units 3 & 4
Areas Mined: C, F
Production: 6.9 MTPY
Avg. Eff. Ratio: 5.4 BCY/Ton
- Mine operating cost estimates are based primarily on cost history at
Rosebud Mine. Estimated mining costs (excluding royalties, production
taxes, and non-cash expenses) over the study period are summarized:
1998 DOLLARS PER TON
------------------------------------------------------
UNITS 3 & 4
UNITS 1 & 2 (AREAS C & F)
(AREAS A, B, & D) ---------------------------------
TOTAL MINING TRANSPORTATION TOTAL
----------------- ------ -------------- -----
1999.......................... 4.47 3.56 0.22 3.78
2000.......................... 4.34 3.38 0.22 3.60
2001.......................... 4.10 3.49 0.22 3.71
2002.......................... 3.87 3.54 0.22 3.76
Through Contract Term*........ 4.36 4.35 0.22 4.57
Term Through 2030............. 5.12 5.01 0.22 5.23
- ---------------
* 2003 - 2009 for Units 1 & 2 and 2003 - 2019 for Units 3 & 4
- Capital expenditure requirements over the plan period total $242 million.
The bulk of this is for rebuilds and replacement of existing equipment.
5. WECO negotiated a coal sales agreement with Minnesota Power Company in
July of 1999. This agreement provides for sale of up to 1.5 million tons
annually beginning in January 2000 for an undisclosed term. Mining plans
developed by WECO and those presented herein do not include these additional
sales, and WECO reportedly has not developed the specific plans for production
of this coal. Incorporating this tonnage in the mining plan would have some
affect on the plan, and could affect capital and operating cost projections.
BOYD has reviewed the potential impact of this additional tonnage on fuel
prices, and considers any impact under the current contracts likely to be
minimal. Development of revised mine plan and cost projections, however, in our
opinion, would not likely result in substantial changes to the findings of this
study.
6. The Corette plant obtains fuel from the large mines in the SPRB under
short-term agreement. The SPRB will continue to be a viable coal source for
Corette throughout the study period, with delivered prices depending on market
price for coal and the cost of rail transport to Corette.
Corette requires a relatively low-sulfur coal to meet air quality
regulations in the Billings area. Currently, acceptable coal is available at a
competitive cost; however, it is possible the lower sulfur fuel may command a
premium in the future.
The SPRB also provides a potential alternative fuel source for Colstrip
upon termination of the present contracts, and provides a competitive
alternative to the Rosebud Mine in any contract extension negotiations. We
anticipate SPRB coal will remain a viable fuel source for Colstrip throughout
the projected life of the plant (through 2048).
2-3
286
7. Coal sales at the Colstrip Station are governed by two long-term supply
contracts. Both are full-requirements contracts, and thus pricing is generally
independent of external market trends. Key features of these contracts are
summarized:
UNITS UNITS
1 & 2 3 & 4
--------------- ---------
Date............................................. 7/30/71 8/24/98
Expiration....................................... 12/31/09 12/31/19
Re-openers....................................... 2001 none
Pricing Structure................................ Base Price Cost Plus
plus Escalation
The "cost plus" structure of the Units 3 & 4 contract is the result of a
recent negotiation, and will be phased in over the 1999 - 2001 period. A price
reduction in excess of 25% is expected as a result of this negotiation.
8. Estimated fuel price for Units 1 & 2 over the remaining term of the
contract are:
UNITS 1 & 2 DELIVERED FUEL PRICE (1998 DOLLARS)
--------------------------------------------------------
2003 -
1999 2000 2001 2002 2009 AVERAGE
----- -------- ----- ----- ------ -------
Tons/Yr (000).................. 1,510 3,020 3,020 3,020 3,020 3,020
Quality -- Btu/lb.............. 8,558 8,558 8,558 8,558 8,558 8,558
Contract Price ($/Ton):
Commodity Charge............. 5.79 5.78 5.78 5.19 5.31 5.41
Fixed Charge................. 1.31 1.39 1.42 1.44 1.48 1.46
Royalties*................... 1.04 1.04 1.05 0.96 0.98 1.00
Quality Adjustment........... (0.14) (0.14) (0.14) (0.13) (0.13) (0.13)
----- -------- ----- ----- ----- -----
Total................ 8.00 8.078.0 8.11 7.46 7.64 7.72
Fuel Price ($/MMBtu)........... 0.47 0.47 0.47 0.44 0.45 0.45
- ---------------
* Includes production taxes associated with royalty payments.
To estimate fuel prices after contract expiration, we assumed a new
contract with a "cost plus" structure similar to that for Units 3 & 4 would be
implemented with pricing terms competitive with the cost of SPRB coal.
Under this assumption, fuel costs over the remaining contract term average
$10.70/Ton or $0.61/MMBtu.
9. Fuel prices for Units 3 & 4 include not only the FOB mine price, but
also a charge to transport the coal via conveyor to the plant. These estimated
delivered fuel prices are:
UNITS 3 & 4 DELIVERED FUEL PRICE (1998 DOLLARS)
-----------------------------------------------------
2003 -
1999 2000 2001 2002 2019 AVERAGE
----- ----- ----- ----- ------ -------
Tons/Yr (000)..................... 3,485 6,971 6,971 6,971 6,971 6,971
Quality -- Btu/lb................. 8,509 8,509 8,509 8,509 8,509 8,509
Contract Price ($/Ton):
Commodity Charge................ 9.52 7.35 5.91 6.24 6.91 6.92
Fixed Charge.................... 0.68 0.91 1.14 1.18 1.37 1.31
Royalties*...................... 1.70 1.44 1.17 1.23 1.37 1.36
----- ----- ----- ----- ----- -----
Subtotal................ 11.90 9.70 8.22 8.65 9.65 9.59
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287
UNITS 3 & 4 DELIVERED FUEL PRICE (1998 DOLLARS)
-----------------------------------------------------
2003 -
1999 2000 2001 2002 2019 AVERAGE
----- ----- ----- ----- ------ -------
Transportation ($/Ton)............ 1.62 1.62 1.27 0.91 0.92 0.99
Total Cost:
$/Ton........................... 13.52 11.32 9.49 9.56 10.57 10.58
$/MMBtu......................... 0.79 0.67 0.56 0.56 0.62 0.62
- ---------------
* Includes production taxes associated with royalty payments.
After expiration in 2019, we assumed the contract will be extended under
the current structure, but with pricing terms competitive with the cost of SPRB
coal. Estimated average delivered price is $10.19/Ton or $0.59/MMBtu.
10. The Corette Station will most likely continue to purchase SPRB coal at
market prices under short-term agreements. Estimated delivered price is
summarized:
DELIVERED PRICE (1998 DOLLARS)
-------------------------------------------
2001 - 2006 -
1999 2000 2005 2030 AVERAGE
---- ---- ------ ------ -------
FOB Mine ($/Ton)............................. 3.65 4.10 4.90 5.40 5.23
Transportation ($/Ton)....................... 5.06 5.06 5.06 5.06 5.06
---- ---- ---- ----- -----
Total.............................. 8.71 9.16 9.96 10.46 10.29
$/MMBtu @ 8,330 Btu/lb....................... 0.52 0.55 0.60 0.63 0.62
Corette requires a relatively low sulfur content coal to meet emissions
standards. Ample supplies are currently available; however, if supplies tighten,
the cost of the lower sulfur coal could increase.
11. The Colstrip plant is projected to continue operation through 2048,
some 18 years beyond the study period addressed in this report. Projections of
fuel supply and costs that far into the future are highly speculative and are
not developed in this report. However, certain factors which may affect such
future supplies are addressed, specifically:
- Several options exist for fuel supply after depletion of the economic
reserves at Rosebud. The SPRB is the most likely fuel supply source. It
is anticipated that adequate supply capacity will exist in the SPRB
through the anticipated life of the plant. Other supply alternatives are
also available.
- Coal from the SPRB would most likely be transported to Colstrip via rail.
The necessary rail infrastructure is in-place at this time, and we are
unaware of any circumstance that would impair the railroad's ability to
deliver fuel in the quantities needed.
- Receiving SPRB coal at Colstrip would require construction of rail
unloading facilities and modifications to the coal handling systems. The
cost of such facilities would depend on the specific design and ability
to integrate a new facility into the existing system. We estimate this
capital cost could range between $10M and $25M (1998 dollars), depending
on these factors. Assessment of impacts (or necessary modifications) on
plant operations are beyond BOYD's scope of work. However, the SPRB and
Rosebud coals are very similar, and we would expect any impacts to be
limited.
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GEOLOGY AND RESERVES
3.1 INTRODUCTION
Western Energy Company's (WECO) Rosebud Mine is situated near the town of
Colstrip in southeastern Montana and lies within the northern (Montana) portion
of the Powder River Basin coal region. The coal seams of interest in the
Colstrip area are subbituminous in rank and occur geologically in the Paleocene
Age Fort Union Formation. The Rosebud coal is similar geologically to other
coals in the region that are mined for power plant fuel, and is recoverable by
surface mining methods.
This chapter addresses the geology of the coal resources available to the
Rosebud Mine, the extent of the reserves, and the quality of that coal from the
standpoint of providing an adequate coal supply to the Colstrip Generating
Station.
3.2 LOCATION AND ACCESS
The Rosebud Mine is located in southeastern Montana's Rosebud County, east
and south of the town of Colstrip. Billings, Montana, the largest city in the
region, is located approximately 120 miles to the west. Highway access to the
property from Billings is by way of Interstate Highway 94 and State Highway 39
to the town of Colstrip. Rail access is provided by a spur line of the
Burlington Northern Santa Fe (BNSF) Railway. The nearest commercial airport is
at Billings.
The Colstrip Generating Station lies immediately south of the town of
Colstrip, but lies within the town boundaries as defined by an incorporation
election in November 1998.
3.3 TOPOGRAPHY AND DRAINAGE
The Rosebud coal deposit is located along Armells Creek and on the drainage
divide south of the creek. Armells Creek is an intermittent stream with a gentle
gradient that flows northeast through the deposit during periods of high
precipitation and spring runoff. Most of the terrain is gently rolling, but near
the northern and eastern edges, it is relatively steep and deeply dissected.
Ridges formed of clinker (an erosion-resistant rock formed by the in-situ
burning of the underlying coal seams) dominate the higher elevations in these
areas. Prominent ridges and steep-sided valleys are also found to the southeast
where the Sawyer coal bed, which lies above the Rosebud bed, has formed clinker,
capping the ridges between the valleys of the north and south forks of Cow
Creek.
Part of the alluvial valley of Armells Creek is utilized for dry land
farming. Hay is raised in meadows along the valley bottoms. Mining generally
avoids these valley floor areas.
3.4 PROPERTY OWNERSHIP AND CONTROL
WECO controls in excess of 35,000 acres of coal leases in Rosebud and
Treasure Counties, Montana. Coal lessors include:
- Great Northern Properties (GNP), the successor in ownership to the
Burlington Northern Railroad land grant checkerboard. GNP is lessor of
approximately 20,000 acres or 56% of the WECO leasehold. The GNP
properties generally carry a 12.5% (of realization) royalty and can be
held indefinitely by production.
- U.S. Bureau of Land Management (BLM) leases approximately 14,000 acres to
WECO. These leases also carry a 12.5% royalty and are subject to the
various rules and regulations associated with federal leasing.
- State of Montana is a lessor on about 4% of the WECO landholding. These
leases are subject to royalties comparable to the federal lands.
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The Rosebud Mine coal lands encompass an area of approximately 60 square
miles (38,775 acres) in Townships 1 and 2 North, Ranges 40, 41, and 42 East.
WECO's ownership of coal rights within this area is illustrated on Figure 3.1
(following this page).
Surface rights in the area are controlled primarily by WECO or GNP. GNP's
coal leases convey to WECO full surface disturbance rights. Other lands in the
area are owned by a limited number of large landowners or the State of Montana.
With a few minor exceptions, WECO controls appropriate surface owner consent
within the reserve area assigned to meet current contract requirements.
At the time of our March 1999 study, certain federally owned reserves
within the mine plan remained unleased. WECO obtained a lease on these lands in
June 1999, bidding approximately $4.4 million for the 1,400-acre parcel.
BOYD did not independently perform title searches or confirm the validity
of documentation or information provided by WECO. The documentation reviewed,
including property maps, supported the summary information and generally
confirmed the adequacy of land control. Based on our review, we conclude that
WECO has adequate control of mining rights for coal needed to satisfy existing
contract commitments to the Colstrip Generating Station.
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[Map]
3-3
291
WECO controls mining rights on substantial additional reserve/resource
acreage beyond current contractual commitments. These additional resources could
supply the Colstrip Station upon expiration of the current contract term, or be
sold to third parties.
3.5 REGIONAL GEOLOGY
The Powder River Basin (PRB) coal region encompasses some 20,000 square
miles in a north-south oval-shaped area of northwestern Wyoming and southeast
Montana (see Figure 3.2 following this page). The region is underlain by rocks
of the Fort Union Formation, which form an asymmetrical structural basin along a
north-south axis located near the western flank. The coal seams currently mined
in Wyoming outcrop along the eastern flank of the basin, and dip gently
westward. The beds in the Montana portion of the basin exhibit a regional
southward dip, but are essentially flat lying in most places.
Mineable subbituminous coal seams in the PRB tend to be thick, flat lying,
and relatively undisturbed by geologic anomalies. Seams sometimes merge, split
and reform over distance, and are difficult to correlate across the Basin. In
the Colstrip area, the Rosebud seam is thick and consistent, and is the seam of
primary interest for mining.
3.6 LOCAL/COAL GEOLOGY
The structural setting of the Colstrip region is relatively uncomplicated
with few faults with minor displacements. Seam structure is gently undulating,
dipping at less then one degree to the southeast. The top of the Rosebud seam is
highest in the northwestern part of the area, and lowest in the southeast.
The principal seams in the region are the Rosebud and the McKay (see Figure
3.3). The Rosebud seam averages between 20 and 25 feet of in-place coal.
Eighteen to 60 feet below the Rosebud is the McKay Seam, which averages about 8
feet thick.
The Rosebud Seam resources in the Colstrip area have been actively mined
since 1924, using surface mining methods. Currently, maximum cover depths over
the Rosebud seam in active mining areas are in the range of 180 ft. The McKay
Seam is not recovered due to quality and cost considerations.
3.7 EXPLORATION
Exploration efforts to define the Rosebud Mine reserves have relied
primarily on rotary and core drilling. The first significant drilling by WECO at
the Rosebud Mine began in the early 1970's. Since then, a number of drilling
programs have been completed, resulting in a large body of exploration data
defining the resource.
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[REGIONAL MAP POWDER RIVER BASIN OF WYOMING & MONTANA]
3-5
293
[GRAPH]
3-6
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Exploration data is the basis for resource characterization, and the more
data available the better, or more reliable, that characterization. Typically,
reserve estimates are categorized by reliability to indicate the degree of
assurance of the estimate. Reserve estimates for deposits that (unlike the
Rosebud Mine) are inadequately explored are not generally reliable and may not
provide a sound basis for mine planning and/or fuel supply definition.
Reserve reliability categories as defined by the United States Geologic
Survey are:
- Proven (Measured) is the highest degree of geologic assurance. Estimates
of quantity and quality are well defined by exploration data. The points
of observation are closely spaced to accurately determine the physical
characteristics and overall mineability of the seam. This definition is
predicated on a systematic arrangement of holes in a grid pattern, and
does not allocate an area of proven reserve around isolated or
wide-centered holes. As used in this report, proven tonnage is defined as
being within 1/4 mile of an observation point (nominal drill hole spacing
of 1/2 mile).
- Probable (Indicated) is a moderate degree of geologic assurance.
Estimates of quantity are computed from projections of nearby and/or
widely spaced observation points. As used in this report, probable
tonnages are within 3/4 mile of an observation point.
- Inferred indicates inadequate definition of the reserve, and therefore a
high degree of geologic risk. These would typically be resources located
beyond the limits of the probable classification.
The density of the exploration data at the Rosebud Mine is sufficient to
place the coal reserves estimates in the proven and probable categories for all
areas of the mine. Over 95% of the reserve is in the proven category. This gives
a high level of assurance of the accuracy of reserve estimates, and provides a
sound basis for fuel supply definition and planning.
3.8 RESERVE AUDIT PROCEDURES
To confirm the available reserve tonnages, BOYD audited WECO's reserve
estimates. The audit process addresses the adequacy of the database and the
reasonability of the procedures used by WECO to estimate the quality and
quantity of economically recoverable coal. To perform the audit, BOYD reviewed
methodologies and assumptions used by WECO in developing reserve estimates and
mine plans. We also audited the geological interpretations and coal quality
projections to determine whether they accurately reflect the underlying data and
are developed using techniques and parameters accepted in the industry.
Specifically, BOYD took the following steps to assess WECO's geologic
interpretations and reserves estimates:
- Met with personnel from WECO and discussed the geology, coal reserves,
and methodologies used to generate reserves on the property.
- Completed a site visit of the property.
- Reviewed geophysical logs for reasonableness of coal seam and overburden
thickness determinations.
- Reviewed seam correlations for consistency and accuracy.
- Cross-checked the thicknesses picked from the geophysical logs with the
lab results from the coal intervals that were sampled and analyzed.
- Maps generated by geologic modeling computer software (Vulcan) were
randomly checked against the exploration database to ensure that the
output was representative of the underlying data.
- Coal reserves and overburden volumes were checked using these maps, and
compared to the reserves and overburden volumes reported by WECO.
- The coal quality database for Areas C and D were checked against the
quality maps to insure that the maps reasonably reflected the exploration
information.
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295
This audit process indicated that WECO's estimates of coal reserve tonnages
and quality are reasonable, based on adequate data, and are developed by
application of techniques and parameters accepted in the industry. The estimates
provide a reliable basis for mine planning and fuel supply assessment.
3.9 COAL RESERVES AND RESOURCES
This section addresses the quantity of coal reserves and resources
available at the Rosebud Mine. Estimates are provided by WECO (except as noted)
as of 1998. These have been adjusted by BOYD to reflect anticipated depletion
through June of 1999.
3.9.1 Mining Areas
For purposes of reserve definition, mine planning, and contract
commitments, WECO divides the Rosebud Mine into six reserve areas (see Figure
3.4 following this page):
- AREA A. Area A lies immediately west of the town of Colstrip. The
Rosebud seam reserve covers 261 acres and averages approximately 22 feet
thick in this area. Overburden depth ranges from subcrop to over 340
feet, averaging 150 feet. Area A was mined extensively in the past;
however, it has been inactive since 1994 because of market declines,
increasing overburden depth, and high stripping ratios.
- AREA B. Area B lies south and southwest of Colstrip along the southern
side of Armells Creek. The Rosebud seam reserve covers approximately 640
acres in Area B and averages 24.5 feet thick. Overburden depth averages
128 feet, and, as with Area A, mining has taken place in Area B. Area B
has been inactive since 1995 because of increasing overburden depth and
stripping ratios.
- AREA C. Area C lies west of Areas A and B, approximately 5 miles
southwest of Colstrip. The area is currently active and is the source of
coal dedicated to Units 3 & 4. The Rosebud seam covers over 3,475 acres,
averaging 23 feet thick. Overburden depth ranges to over 350 feet,
averaging just over 97 feet throughout. The coal reserves in Area C form
the bulk of the mineable reserves at the Rosebud Mine.
Area C is further subdivided into five individual mining areas (Areas
C -- South, East, Central, North, and West). Current mining is in C-South
and C-East.
- AREA D. Area D lies immediately northeast of Colstrip, and is actively
being mined. The Rosebud Seam covers approximately 1,000 acres and
averages just less than 22 feet thick in Area D. Overburden depth ranges
from subcrop to over 260 feet, averaging 112 feet throughout. Area D is
dedicated to Colstrip Units 1 & 2.
- AREA E. Area E lies southeast of Colstrip and is fully depleted.
- AREA F. Area F is the westernmost of the reserves controlled by WECO,
lying west of Area C and 14 to 15 miles west of Colstrip. The Rosebud
Seam covers approximately 2,400 acres and averages 20.4 feet thick in
this area. Overburden depth ranges from subcrop to over 250 feet. Area F
has been identified by WECO as an area of future reserves. It is not
dedicated to any customer, and has not been the subject of detailed
reserve studies or mining plans.
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[Map]
3-9
297
The individual reserve areas are bounded by geologic/geographic features or
mine planning criteria such as overburden depth. In certain cases, additional
tonnage could be recovered by extending mining into deeper cover. Such potential
extension areas include Areas A, B, C-South, C-Central, C-West, and F. Coal
resources in these areas are available for mining, but are not included in
WECO's current plans. (Mining of these resources is not required by the plans
developed herein until approximately 2028.) The McKay Seam is not considered
mineable in any area.
3.9.2 Reserve/Resource Groups
Coal resource estimates have been summarized by groups for purposes of this
report. These groupings are:
- Assigned Reserves. Assigned reserves are those recoverable coal and
reserves "assigned" to satisfy WECO's contractual fuel supply obligations
to the Colstrip Generating Station. These reserves effectively comprise
the remaining tonnages in Area C (for Units 3 & 4) and Area D (for Units
1 & 2). WECO has developed long-term mine plans to recover these
reserves.
- Supplemental Reserves. Supplemental reserves are those tonnages that are
considered mineable by WECO if adequate prices can be obtained. These
reserves are in Areas A and B, and for long-term commitments, Area F. The
supplemental reserves could be available for the Colstrip Station under
an extension of the current contracts, or for outside sales.
- Extended Resources. The extended resources are those tonnages accessible
by extending current mining plans into deeper cover areas. These tonnages
are considered marginal or sub-economic at this time, and are therefore
referred to herein as "resources." The coal is well defined (consistent
with the "proven" reliability category) and could be available for
Colstrip under an extension of the current contracts.
These groupings are for purposes of this report and do not, particularly as
relates to the extended resources, reflect WECO's long-range planning
parameters.
3.9.3 Reserve Parameters
Estimating recoverable reserves based on geologic modeling work requires
application of a number of factors and parameters related to the specific
deposit and general mining practices. These parameters as related to the Rosebud
Mine are discussed below.
WECO estimated reserves based on coal volumes developed from the
computerized geologic model and a density of 1,742 tons per acre/foot. This is
within the normal density range for subbituminous coals.
Some coal will inevitably be lost in the mining process; thus, not all of
the in-place resource is recoverable. In WECO's case, these mining losses are
increased by the need to selectively mine the seam for quality reasons. In the
Rosebud Seam, certain impurities (particularly sulfur) tend to concentrate in
the top and bottom 6 inches to 12 inches of the seam. WECO removes the top 6
inches prior to loading the coal, and leaves an average of 10 inches of the seam
bottom in-place. By excluding these small, poor quality sections, overall
product coal quality is significantly improved. Considering these and normal
mining losses, the effective mining recovery applied in estimating recoverable
coal reserves is 94%. This figure is consistent with past history at the mine
and with analyses based on quality parameters.
Some of the top waste coal and weathered outcrop coal (these tonnages are
not included in reserve estimates) are mined and used as feed stock for the
Colstrip Energy Partners L.P. (CELP) power plant located 8 miles north of
Colstrip. Since 1991, CELP waste coal purchased from the Rosebud Mine has
averaged 240,000 tons per year. The arrangement has been mutually beneficial for
both WECO and CELP.
The rock and soil material above the Rosebud coal seam is referred to as
overburden. Overburden (typically measured in bank cubic yards or BCY) must be
removed (or "stripped") to expose the coal seam, and overburden removal is
typically the most important cost factor at the mine. Estimates of overburden
volumes were made by BOYD based on WECO's geologic model and are included with
reserve estimates. The
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"stripping ratio," expressed in BCY per ton, is the volume of overburden which
must be removed to expose one ton of recoverable coal in the surface mining
process.* Stripping ratio provides an indicator of the relative economics of
different reserves. The Rosebud Mine in recent years has experienced virgin
stripping ratios in the range of 3.0 - 3.5 BCY/ton.
3.9.4 Reserve Estimates
Estimated proven and probable, recoverable (raw product) coal reserves for
Rosebud total about 300 million tons, as summarized below and detailed on Table
3.1 following this text.
COAL RESERVE SUMMARY
-------------------------------------------
IN-PLACE RECOVERABLE VIRGIN
TONS TONS STRIP RATIO
AREA (000) (000) (BCY/ TON)
- ---- ------------- ----------- -----------
Assigned Reserves:
Area C............................................... 151,307 142,228 4.1
Area D............................................... 42,777 40,211 4.7
------- ------- ---
Subtotal..................................... 194,085 182,439 4.2
Supplemental Reserves:
Area A............................................... 10,000 9,400 6.7
Area B............................................... 27,234 25,600 5.1
Area F............................................... 85,000 79,900 4.8
------- ------- ---
Subtotal..................................... 122,234 114,900 5.1
------- ------- ---
Total Reserves......................................... 316,319 297,339 4.6
In excess of 95% of these reserves are considered proven. In addition to
the assigned and supplemental reserves, estimated "extended resources" are
defined and available for mining within the current mine area. These resources
are considered subeconomic at this time, but would be available over the long
term should economics change.
3.9.5 Colstrip Station Requirements
Reserves required to fuel the Colstrip station under the current contracts
are estimated at 175 million tons, based on fuel consumption projections
provided by R. W. Beck.
EXPIRATION REQ'D TONS
CONTRACT DATE (000)
- -------- ---------- ----------
Units 1 & 2............................................ 2009 31,710
Units 3 & 4............................................ 2019 142,905
-------
Total........................................ 174,615
Based on these estimates, the assigned reserves at Rosebud are sufficient to
meet contractual obligations to the Colstrip Station.
If Rosebud continues to supply the Colstrip Station via contract extensions
through 2030, an additional 138 million tons will be required. Sales to other
customers during this same period are estimated at 6 million tons, bringing
total reserve requirements through 2030 to approximately 319 million tons. This
exceeds the reserves available at Rosebud (which are adequate for planned
operations through approximately 2028) and require mining some of the "extended
resources" (estimated at about 25 million tons) to fuel the plant through the
study period. This need to recover extended resources will be exacerbated by any
additional third
- ---------------
* Two stripping ratio figures are commonly quoted. "Virgin" stripping ratio is
the in-place (or "virgin") BCY divided by recoverable tons. The "effective"
stripping ratio is the sum of in-place BCY and dragline rehandle BCY divided
by the recoverable tonnage.
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party sales secured by WECO. In July 1999, WECO negotiated such a sale,
committing 1.5 MTPY to Minnesota Power Company over a multi-year contract (the
contract term is confidential). Current market conditions are not generally
favorable for third party sales of Rosebud coal in terms of both price and
quality. While we expect WECO will sell some additional third party coal, we
would not, given this market situation, expect such sales to be in large
tonnages over the long term. Any such sales will, however, limit the reserves
potentially available to Colstrip beyond current contract commitments.
Beyond 2030, we believe that coal available from alternative sources will
be less expensive than mining the "extended resources" at Colstrip. While these
"extended resources" will be available, they will probably not be mined.
3.10 COAL QUALITY
Coal quality estimates are based on analytical data gathered in the course
of exploration of the deposit. This data is incorporated in the geologic model
and extrapolated to estimate in-place and product coal quality. The resulting
estimates of delivered coal quality are discussed in this section.
3.10.1 Data Extent and Adequacy
Extensive coal quality data were collected on both the Rosebud and, to a
lesser extent, on the McKay coal seams during the WECO exploration programs from
the early 1970's through 1998. The extent of the available coal quality data is
sufficient to categorize the coal quality estimates as proven and probable. This
provides a reliable basis for projecting future fuel quality.
3.10.2 In-Place Coal Quality
In-place quality is estimated from independent laboratory analyses of the
full Rosebud Seam thickness and compiled using computer geologic modeling
techniques. Estimated in-place reserve quality by area is summarized below and
on Table 3.2 following this text.
IN-PLACE AS-RECEIVED BASIS
------------------------------------
MOISTURE ASH SULFUR
AREA (%) (%) BTU/LB (%)
- ---- -------- ---- ------ ------
A 25.59 9.11 8,530 0.93
B 25.52 8.97 8,580 0.80
C 25.91 9.90 8,375 0.91
D 26.75 8.96 8,467 0.84
F 25.59 9.72 8,470 0.94
----- ---- ----- ----
Average 25.91 9.61 8,436 0.90
Based on our review of the data and modeling procedure, we consider these
estimates reasonable.
3.10.3 Selective Mining
The Rosebud coal seam is characterized by the presence of high sulfur and
ash values in the top and bottom 6 to 12 inches of the coal seam. This allows
the mine to improve the quality of the product coal by selectively separating
and discarding (or selling as waste coal) the top and bottom of the seam,
leaving only the higher quality middle portion. Thus the quality of the middle
portion, which is sent to the Colstrip Station, is not degraded by the
poor-quality top and bottom material, as it would have been had the full seam
been mined. This selective mining practice enhances the product and is a
significant consideration in estimating product coal quality.
To determine the thickness of poorer quality material, the exploration
cores must be split and the top and bottom sampled and analyzed separately. This
"ply-by-ply" sampling technique is now standard procedure at Rosebud and
reliably estimates the quality of coal recovered using selective mining
techniques.
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Unfortunately, prior to 1995, the importance of ply-by-ply sampling was not
realized, and many of the earlier cores were analyzed as one sample of the full
seam thickness. In such a case, the quality of the full core is lower than can
be achieved by selective mining, but it is not possible to know by exactly how
much, because separate analyses of top and bottom were not made. Much of WECO's
pre-1995 exploration data reflects these full-seam samples, and thus understates
the actual quality of coal that can be produced. WECO therefore decided to
derive a global adjustment methodology that could be applied to this older data
to accurately estimate probable product quality. This was the purpose of a
"Quality Assessment Study" undertaken in 1995, based on 27 cores in Area D, and
some 51 core holes drilled in 1979 - 1981. This data indicated the following
typical quality variations in the seam:
IN-PLACE COAL QUALITY
AS-RECEIVED BASIS
--------------------------------------
MOISTURE ASH SULFUR
INTERVAL (%) (%) BTU/LB. (%)
- -------- -------- ----- ------- ------
Top....................................... 20.24 24.92 7,135 5.35
Middle.................................... 27.05 7.92 8,577 0.67
Bottom.................................... 22.96 26.15 6,456 2.58
----- ----- ----- ----
Composite................................. 26.75 8.96 8,467 0.84
Thus, by selectively mining the coal (separating or not taking the top 6
inches and bottom 12 inches), the coal quality is improved, with a decrease in
sulfur of 0.17% (0.84% - 0.67%), a decrease in ash of 1.04% (8.96% - 7.92%), and
an increase of 121 Btu/lb.
To utilize the older data insofar as possible in conjunction with the 1995
ply-by-ply analysis, WECO derived adjustment factors for estimating recoverable
coal:
- For predicting mined coal quality, weigh the 1995 drilling program
quality results and the as-mined quality results equally.
- For predicting mined coal quality other than sodium, give the pre-1995
results weighting factor equal to 20% of the 1995 program results.
- For predicting mined sodium, weigh all results equally. This decision was
based on an observation of better agreement between drilling program
sodium results than between other quality characteristics.
The above adjustments were made to the Area D database, and the resulting
estimated recoverable coal quality by WECO is based on these factors. Similar
types of adjustments were derived for Areas A, B, and C and correlated to
recovered coal quality. WECO has not determined an adjustment factor for Area F
because there has been no coal mined to form a basis for the adjustment.
BOYD has reviewed this adjustment procedure for predicting recoverable coal
quality, and considers it reasonable.
3.10.4 Recoverable Coal Quality
The recoverable coal quality for Areas A and B are projected from the WECO
computer model. The recoverable coal quality for Areas C and D was estimated
from in-place coal quality using the adjustment factors discussed above.
Recoverable coal quality for Area F was not estimated by WECO because no coal
has been mined in Area F, and no sampling has been done on a ply-by-ply basis.
For purposes of this report, BOYD applied the parameters from the 1995
drilling program in Area D (the difference between the coal and the composite
intervals) to estimate recoverable quality in Area F. The estimated recoverable
coal quality of the Rosebud Mine reserves is summarized below and detailed on
Table 3.2.
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RECOVERABLE COAL QUALITY
AS-RECEIVED BASIS
------------------------------------
MOISTURE ASH SULFUR NA(2)O
AREA (%) (%) BTU/LB (%) (% IN ASH)
- ---- -------- ---- ------ ------ ----------
Assigned Reserves:
Area C....................................... 25.97 9.32 8,509 0.68 0.49
Area D....................................... 26.83 7.95 8,558 0.62 0.58
----- ---- ----- ---- ----
26.16 9.02 8,520 0.67 0.51
Supplemental Reserves:
Area A....................................... 25.54 8.91 8,713 0.72 0.54
Area B....................................... 25.51 8.85 8,739 0.72 0.30
Area F....................................... 25.29 8.68 8,591 0.77 1.05
----- ---- ----- ---- ----
25.36 8.74 8,634 0.75 0.84
Total Reserves....................... 25.85 8.91 8,564 0.70 0.64
Recoverable coal quality generally meets contract specifications. However,
there are "pockets" of high-sodium coal that could be problematical for Units 1
& 2, even when product quality is within specifications. One such pocket will be
encountered in Area D (which supplies Units 1 & 2) late in the contract life.
Alternative mining plans or blending with Area C coal may be desirable at that
time.
Following this text are:
Tables
3.1: Coal Resource Summary
3.2: Coal Quality Summary
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TABLE 3.1
COAL RESOURCE SUMMARY
ROSEBUD MINE
ROSEBUD COUNTY, MONTANA
FOR
CHASE SECURITIES INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
COAL TONS OVERBURDEN*
SEAM ----------------------- ------------------ VIRGIN
THICKNESS IN-PLACE RECOVERABLE DEPTH BCY STRIP RATIO
AREA ACRES (FT) (000) (000) (FT) (000) BCY/TON
- ---- ----- --------- -------- ----------- ----- --------- -----------
ASSIGNED RESERVES:
Area C:
C West..................... 760 23.7 31,418 29,533 83 101,308 3.4
C North.................... 718 23.7 29,678 27,897 66 76,339 2.7
C Central.................. 479 21.7 18,183 17,092 101 77,758 4.5
C East..................... 777 23.7 32,036 30,114 118 148,247 4.9
C South.................... 1,011 22.7 39,992 37,592 111 180,496 4.8
----- ---- ------- ------- --- --------- ---
Subtotal -- Area C.... 3,745 23.2 151,307 142,228 97 584,148 4.1
Area D....................... 1,040 23.6 42,777 40,211 112 187,256 4.7
----- ---- ------- ------- --- --------- ---
Total -- Assigned..... 4,785 23.3 194,085 182,439 128 771,404 4.2
SUPPLEMENTAL RESERVES:
Area A....................... 261 22.0 10,000 9,400 150 63,146 6.7
Area B....................... 638 24.5 27,234 25,600 128 131,482 5.1
Area F....................... 2,400 20.4 85,000 79,900 100 387,060 4.8
----- ---- ------- ------- --- --------- ---
Total -- Supplemental... 3,299 21.3 122,234 114,900 109 581,689 5.1
TOTAL RESERVES................. 8,084 22.5 316,319 297,339 104 1,353,093 4.6
- ---------------
* Estimated by BOYD based on WECO geologic model.
Note:
"Assigned" = Reserves assigned by WECO to current Colstrip Plant contract
committments.
"Supplemental" = Reserves not included in current mining plans but considered
mineable by WECO.
All reserves are classified as "Proven" and "Probable."
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TABLE 3.2
COAL QUALITY SUMMARY
ROSEBUD MINE
ROSEBUD COUNTY, MONTANA
FOR
CHASE SECURITIES INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
AS-RECEIVED BASIS
----------------------------------------------------------------------
IN-PLACE RECOVERABLE
RECOV. ---------------------------------- --------------------------------- NA(2)O
TONS MOISTURE ASH SULFUR MOISTURE ASH SULFUR IN ASH
AREA (000) (%) (%) BTU/LB (%) (%) (%) BTU/LB (%) (%)
- ---- ------- -------- ----- ------ ------ -------- ---- ------ ------ ------
ASSIGNED RESERVES:
Area C:
C-West...................... 29,533 26.33 8.79 8,448 0.85 26.00 9.55 8,512 0.67 0.35
C-North..................... 27,897 25.67 9.98 8,330 0.98 25.96 9.30 8,506 0.69 0.31
C-Central................... 17,092 25.45 10.37 8,305 0.99 25.94 9.23 8,505 0.69 1.22
C-East...................... 30,114 26.54 9.61 8,437 0.81 26.02 9.38 8,511 0.67 0.58
C-South..................... 37,592 25.45 10.73 8,335 0.93 25.94 9.15 8,508 0.68 0.34
------- ----- ----- ----- ---- ----- ---- ----- ---- ----
Subtotal -- Area C..... 142,228 25.91 9.90 8,375 0.91 25.97 9.32 8,509 0.68 0.49
Area D........................ 40,211 26.75 8.96 8,467 0.84 26.83 7.95 8,558 0.62 0.58
Total -- Assigned...... 182,439 26.09 9.69 8,396 0.89 26.16 9.02 8,520 0.67 0.51
SUPPLEMENTAL RESERVES:
Area A........................ 9,400 25.59 9.11 8,530 0.93 25.54 8.91 8,713 0.72 0.54
Area B........................ 25,600 25.52 8.97 8,580 0.80 25.51 8.85 8,739 0.72 0.30
Area F........................ 79,900 25.59 9.72 8,470 0.94 25.29 8.68 8,591 0.77 1.05
------- ----- ----- ----- ---- ----- ---- ----- ---- ----
Total --Supplemental... 114,900 25.57 9.50 8,499 0.91 25.36 8.74 8,634 0.75 0.84
TOTAL RESERVES.................. 297,339 25.89 9.62 8,436 0.90 25.85 8.91 8,564 0.70 0.64
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ROSEBUD MINE
4.1 INTRODUCTION
The Rosebud Mine is a large surface coal mining operation owned and
operated by Western Energy Company (WECO). WECO is a subsidiary of Entech, Inc.,
which, in turn, is an affiliate of Montana Power Company.
This chapter reviews the existing mine, its equipment, facilities,
production capabilities, and operational performance in the context of the
mine's reliability as a long-term supplier. Future mining plans and projected
operating costs are also addressed.
4.2 PRESENT MINE
4.2.1 Mine Background
The Rosebud Mine was opened in 1968 to provide coal to the Corette Station.
In 1975, with the construction of Colstrip Units 1 & 2, the mine expanded to a
5-million-ton per year (MTPY) capacity with a 60 cu. yd. Marion 8050 dragline
working in Area E. In 1976, a second dragline was installed in Area B to produce
coal under long-term supply contracts with Northern States Power (NSP) and
Wisconsin Power and Light (WPL). Area C was opened in 1983, dedicated
exclusively to Units 3 & 4. In 1986, Area E was depleted and Area D begun for
Units 1 & 2.
In 1995, the contracts with NSP and WPL expired, and were not renewed by
the utilities. Similarly, in 1996 the Corette Station began buying coal from the
Southern Powder River Basin (SPRB) in place of its traditional Rosebud tonnage.
As a result, Rosebud Mine production decreased from over 13 MTPY in 1994 to 8
MTPY in 1996. Annual mine production since 1972 is summarized:
AVERAGE
PERIOD TONS/YR (000)
- ----------- -------------
1972 - 1975 4,745
1976 - 1980 10,363
1981 - 1985 10,742
1986 - 1990 13,342
1991 - 1995 12,956
1996 7,779
1997 9,127
1998 10,499
The reduction in mine production since 1994 has left some idle capacity in
stripping and coal handling equipment. Other equipment has been retired or
transferred to the areas producing coal for the Colstrip Station.
Production is currently limited to fuel for the Colstrip Station, and coal
for a few smaller customers, including:
- Great Lakes Coal and Dock purchases coal for resale as industrial and
stoker coal. This tonnage is limited, estimated at 200,000 tons annually.
- Colstrip Energy Limited Partners (CELP) purchase "waste coal" (the high
sulfur, high ash coal cleaned from the top of the seam in the normal
course of mining) for consumption in their plant located north of
Colstrip. This material is typically in the range of 240,000 tons per
year and is sold under separate loading and transportation agreements.
- Advanced Coal Conversion Process (ACCP) takes up to 450,000 tons per year
from Area A, which provides feedstock to produce approximately 300,000
tons of low sulfur, high Btu syncoal. Approximately 200,000 tons of this
is planned for sale to Units 1 & 2, while the balance would be sold to
industrial or other customers.
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The Rosebud Mine has difficulty competing in current utility coal markets
for rail-served plants, and WECO's mine plans as of March 1999 do not provide
for sales other than the Colstrip Station and the small customers noted above.
In July 1999, WECO negotiated an agreement to sell up to 1.5 MTPY to
Minnesota Power Company over a multi-year term (the precise term of the
agreement is confidential). Producing this additional tonnage is within the
installed capacity of the mine with only minimal additions of labor and
equipment. This additional tonnage could engender a change in mining plans;
however, our understanding is that the mine will generally follow currently
planned pit progressions, and any change would be minor. Revisions to the mining
plans and cost projections in our March 1999 report as a result of the sale to
Minnesota Power are beyond the scope of this update. We consider it unlikely
that such revisions, if they were made, would substantially affect the findings
of that study.
WECO will continue to work to sell coal into the broader utility market,
and may successfully secure some future sales. We would not, however, expect
these sales to be in large volumes over long terms.
Although the mine is managed as a single integrated complex, contractual
provisions relating to reserve dedication, capital equipment assignments, and
cost allocations tend to create two separate mines. For purposes of planning,
budgeting, and costing, the Area C operation (supplying Units 3 & 4) and Area D
(supplying Units 1 & 2) are quasi-independent mines.
4.2.2 Recent Performance
Recent operational performance data for Rosebud are shown on Table 4.1
following this text, and are summarized below:
1995 - 1998
AVERAGE
-----------
Production (Tons/Yr - 000).................................. 9,664
Quality: Ash(%)............................................. 9.44
Sulfur(%).............................................. 0.74
Btu/lb................................................. 8,526
Overburden Removal:
Effective BCY/Yr (000).................................... 36,739
Stripping Ratio (BCY/Ton)................................. 3.80
Labor Force (No. of Employees)*............................. 288
Labor Productivity (Tons/Empl-Hr)........................... 16.1
- ---------------
* All employees -- 1996 and 1997 only
Reported 1999 production through August totaled 6.9 million tons. Mine
performance has been reasonably consistent over the period reviewed, with the
exception of market-driven production decreases. We consider the mine reasonably
well designed and managed, although there is potential for improvement in
operational performance.
4.2.3 Infrastructure and Equipment
Mine infrastructure, such as buildings, roads, power distribution, and coal
handling facilities, is adequate to support production in excess of levels
planned for the Colstrip Station. Over time, various upgrades and modifications
will be necessary, and systems such as roads and power distribution will have to
be expanded. Overall, the mine infrastructure is in good condition and adequate
to supply the Colstrip Station.
Mine equipment data were reviewed and major items viewed in the field to
generally assess condition and suitability for the operation. WECO provided
supplemental information on equipment lifetime operating
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306
hours and percent mechanical/electrical availability for 1997 and 1998 (an
indicator of condition). This data is summarized in Appendix A and discussed
below.
- Draglines. The draglines are the primary mining tools and appear to be
in good condition, achieving generally acceptable availability. The
machines are at an age where regular maintenance and major overhauls are
a necessity to prolong the machine's useful life. Given such regular
maintenance, and the excess capacity available due to production
cutbacks, the draglines are adequate for the needs of the Colstrip
Station.
- Shovels. As with the draglines, the shovels are performing at acceptable
levels but will require regular maintenance and overhauls.
- Coal Haulers. WECO's coal hauler fleet, particularly for Area D, is
relatively old. These machines are adequate now because there is excess
capacity; however, they will require major rebuilds or replacement in the
near future. Monies for these rebuilds/replacements are included in fuel
cost projections.
- Mobile/Support Equipment. Other equipment at the mine appears to be in
fair operating condition, but is, in many cases, relatively old. A number
of these items will require replacement in the near future.
The equipment fleet is adequate (or has excess capacity) to reliably supply
the needs of the Colstrip Station and planned third party sales. However, the
equipment is relatively old, and capital expenditures for rebuilds and
replacements are incorporated in the cost projections.
4.2.4 Labor Force
The January 1999 labor force at Rosebud numbers approximately 315,
including administrative personnel. This represents a 22% reduction from the
mine's peak employment in 1992 - 1994. Personnel assignments are approximately
as follows:
NUMBER OF EMPLOYEES
---------------------------
SALARIED HOURLY TOTAL
-------- ------ -----
Management.......................................... 4 -- 4
Administrative...................................... 52 7 59
-- --- ---
Subtotal....................................... 56 7 63
Operations:
Area D -- Production.............................. 4 45 49
-- Maintenance............................... 5 24 29
-- --- ---
Subtotal....................................... 9 69 78
Area C -- Production.............................. 5 66 71
-- Maintenance............................... 6 45 51
-- --- ---
Subtotal....................................... 11 111 122
CELP Load/Haul.................................... -- 7 7
ACCP Plant........................................ 2 14 16
Area C Conveyor................................... 2 13 15
Other............................................. 1 13 14
-- --- ---
Total -- Operations............................ 25 227 252
Total -- All................................... 81 234 315
Labor productivity averages 15 - 17 tons per employee hour (TPEH). This is
within the typical range for mines with comparable equipment, production levels,
and conditions.
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307
The hourly workers at Rosebud are represented by the International Union of
Operating Engineers under two separate collective bargaining agreements (one for
the mine and one for the conveyor and ACCP facility). These specify competitive
hourly pay rates in the range of $20/hr to $22/hr, and provide management
adequate flexibility relative to work schedules, assignments, etc. The
agreements, which include no-strike clauses, extend through 2001. Generally,
labor relations at Rosebud have not been contentious. Absenteeism, turnover,
accident rates, etc., are within typical ranges in the industry.
The Rosebud labor force is stable, and provides adequate skills and
abilities to reliably operate the mine.
4.2.5 Operating Costs
WECO provided data on direct mine operating costs for 1997 and 1998, and
supplemental data for 1996. This information was reviewed to determine whether
the costs were reasonable as compared to industry norms, and to identify any
areas of particularly high or low costs.
Average direct operating costs for 1996, 1997, and 1998 (11 months) are
summarized:
$/TON
-----------------------------
1996* 1997 1998 AVG.
----- ---- ---- ----
Direct Mining Expense
Overburden Removal........................... 1.29 0.92 1.16 1.12
Coal Loading & Hauling....................... 1.20 0.82 0.78 0.91
Reclamation.................................. 0.89 0.40 0.25 0.48
Crushing/Conveying........................... 0.40 0.34 0.29 0.34
Supervision/Engineering...................... 0.50 0.28 0.28 0.34
Other........................................ 0.23 0.30 0.30 0.28
---- ---- ---- ----
Subtotal.................................. 4.51 3.06 3.07 3.47
Other Costs
Lease Rents & Records........................ 0.02 0.01 0.01 0.01
A & G and Overheads.......................... 1.67 0.85 0.65 1.01
---- ---- ---- ----
Subtotal.................................. 1.69 0.86 0.66 1.02
Total..................................... 6.20 3.92 3.72 4.49
- ---------------
* Cost data not verified; included for comparison purposes only.
Note that these costs do not include depreciation, depletion, and
amortization, nor do they incorporate the substantial production tax and royalty
expense incurred by the mine.
The costs, as shown, reflect significant cost reductions achieved in 1997
and 1998 in spite of a higher stripping ratio. Much of this reduction is in the
A & G and Overheads category, although reductions in operational areas are
evident as well. Reductions in A & G reflect cutbacks at the mine and at WECO's
head office, as well as changes in overhead allocation methodologies that have
reduced costs allocated to the mine. Under the Amended and Restated Units 3 & 4
Coal Supply Agreement, future A & G charges will be determined by parameters
established by an independent accounting firm.
WECO's future plans assume these cost reductions can be maintained over the
long term. BOYD agrees that costs in 1998 are more likely to be representative
of future operations than costs in earlier years, and cost estimates presented
herein are developed accordingly.
4.3 COAL HANDLING AND TRANSPORTATION
Coal for Units 1 & 2 is hauled to the Area D tipple, crushed, and conveyed
directly to the lowering well serving the power plant stockpile. The facility is
equipped with a 250-ton capacity truck dump hopper, McNalley Pittsburgh double
roll primary crusher, and American Pulverizer AC-7F secondary crusher. Rated
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facility capacity is 1,250 tons per hour (TPH) of minus 2-inch coal. The crushed
coal can also be conveyed to a 190-ton rail car loadout bin for third party
sales.
The Area C crushing and conveying system, serving Units 3 & 4, incorporates
primary and secondary crushing facilities, a 4.2-mile overland conveyor system,
and various ancillary facilities. Major components of this system are:
- Area C truck dump with two 250-ton dump hoppers feeding two parallel
single roll primary crushers which reduce the coal to minus 8 inch size.
Each circuit is rated at 1,875 TPH and is capable of independently
feeding the overland conveyor system.
- Secondary crusher, including tramp iron magnet and two McLanahan 30" x
72" double roll crushers sizing the coal to minus 3 inches.
- Overland conveyor system, including 22,203 ft of conveyor in five flights
with 2,200 total drive hp. Conveyors are 48", travel at 800 fpm, and the
system is rated at 1,875 TPH.
- Ancillary facilities include a dust collection system, water supply, and
electrical, mechanical, and maintenance buildings.
The overland conveyor delivers coal directly to the Units 3 & 4 coal
handling facility. This facility is rated at 1,550 TPH, which limits the
effective capacity of the overland conveyor.
The existing conveyor system operates reliably and is adequate for
projected fuel needs for Units 3 & 4. Overall, the Rosebud coal handling
facilities are suitable for the plant.
4.4 ENVIRONMENTAL AND PERMITTING
The Rosebud Mine operates under a number of environmental-related permit
provisions, the most important of which are incorporated in the Surface Mining
Permit issued by the Montana Department of Environmental Quality. This permit is
in conformance with requirements of the Surface Mining Control and Reclamation
Act (SMCRA) and subject to oversight by the Federal Office of Surface Mining.
The environmental and permitting status of the Rosebud Mine was discussed
with WECO personnel, and the permit documents reviewed to identify any issues
that could affect the continued operation of the mine. The mine's records of
inspections and regulatory compliance activities were also reviewed.
WECO is generally in compliance with applicable laws and regulations as
they are enforced in the region. The reclamation effort is good, and the mine
has won several awards for excellence in mined land reclamation.
Major outstanding environmental issues are minimal. There have been
questions raised about the probable hydrological consequences of mining in Area
C under the "least cost" mining approach. Mine staff considers these questions
related mostly to lack of data, and believes the issue will be resolved
favorably. If for some reason regulatory authorities did not approve these
permit changes related to "least cost" mining, the previous mine plan (a
"levelized" approach) provides an alternative. This previous plan is fully
permitted, and, while it would not have certain of the benefits of "least cost"
mining, it could be followed with no interruption to mining operations.
Certain portions of Area D are not within the currently permitted area.
This permit modification is expected to be approved in 1999.
Planned mining through 2019 will concentrate in areas that are currently
active and where the environmental issues are well defined. Area F, which is
planned for mining after 2019, is less well defined. While mine personnel are
unaware of any environmental limitations associated with Area F, there is still
a degree of uncertainty.
Overall, our review indicates that environmental and permitting activities
at Rosebud are consistent with industry norms. There do not appear to be any
environmentally related issues that constitute a "fatal flaw" or pose a
significant risk to the fuel supply.
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The "least cost" mining approach will result in extensive final pits at the
conclusion of mining. These are expensive to reclaim and will constitute a
significant liability. WECO indicates that the liability is fully funded for
Area C at this time (except for Puget Sound Power & Light's share, which is on
an accrual basis). Area D is funded via an accrual. As a result, the Colstrip
Station owners should not have any outstanding obligation as regards final
reclamation at the conclusion of the current contracts. BOYD has not verified
the sufficiency of these accruals or legal obligations for final reclamation.
4.5 MINING PLANS
By assignment, BOYD projected future operations over a 30-plus year period
extending from July 1, 1999, to December 31, 2030. This significantly exceeds
WECO's planning horizons, which extend through the expiration of the existing
contracts in 2009 (for Units 1 & 2) and 2019 (for Units 3 & 4). WECO has
developed two independent plans along these lines, one to satisfy each contract.
We reviewed WECO's plans and believe they are generally accurate and represent a
logical exploitation of the deposit. To extend these plans through 2030, we
assumed that operations will continue beyond WECO's plan without major changes
in production levels, methods, or equipment. The extended mining plan will
recover the remaining supplemental reserves (Areas A, B, and F) and, in the
final 2-3 years (2028 and later) certain deeper coal resources available via a
logical continuation of WECO's planned operation.
WECO's plans are based on typical or historic plant consumption levels of
2.85 MTPY for Units 1 & 2 and 6.5 MTPY for Units 3 & 4. Based on input from R.W.
Beck, we have modified the plans to produce 3.02 MTPY for Units 1 & 2 and 6.971
MTPY for Units 3 & 4. These tonnages are consistent with station generation
plans.
WECO's plans, which form the basis for mine plan and cost projections
presented herein, do not incorporate the 1.5 MTPY sales to Minnesota Power under
the contract negotiated in July 1999. Revisions to the projections herein to
include this tonnage are beyond the scope of this update. We consider it
unlikely that such revisions, if made, would substantially affect the fuel cost
projections presented herein.
This section discusses WECO's mine plans and BOYD's extensions through
2030.
4.5.1 Planning Concept
Units 1 & 2 are supplied by Mining Area D. WECO's plan projects this to
continue, scheduling mining in Area D through year 2010 and thus covering
projected coal sales through the end of the coal sales contract in 2009. Coal
quality is a key design criterion, with areas of high sodium coal (Na(2)O in
ash) deferred until the last years of the plan. Also, late in the plan, the mine
will encounter areas of relatively deep, high-ratio coal.
BOYD's modification of the WECO plan assumes the contract will be extended
and Area D worked to depletion in 2010. After that, the operations fueling Units
1 & 2 will move to Area B, depleting the remaining "supplemental" reserves, then
to Area A, also depleting the available supplemental reserves. In the later
years of the plan, the mine returns to Area B and recovers additional,
relatively deep cover coal from the "extended resource" area. This mining
schedule is shown on Table 4.2 following this text.
Units 3 & 4 are fueled by the Area C operation. The mine-planning
philosophy for Area C is a "least cost" approach originally proposed in
conjunction with an arbitration of the coal supply contract. The current
contract mandates this "least cost" mining, and WECO has developed mine plans
accordingly. The "least cost" approach favors mining of low cover, low strip
ratio reserves first, deferring high cost coal until later in the mine life. As
a result, initial costs are low, but will increase over the life of the mine.
WECO's mine plan projects continuing operations in Area C through contract
termination in 2019. At that time, the available reserves within currently
defined mining limits in Area C will be effectively depleted. BOYD's
modifications assume production consistent with projected Units 3 & 4 burn, and
that after depletion of Area C, operations move to Area F for the duration of
the study period.
Mining in Area C is not progressing precisely according to plan due to
delays in obtaining federal coal leases. As a result, the current near-term plan
is not integrated with the long-term plan for the area. For
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purposes of this report, we have modified the long-term plan to be consistent
with the short-term situation at Rosebud as of January 1999. This modification
presents a reasonable projection of future mining suitable for this study, but
may not precisely reflect WECO's formal plans. This mining schedule is shown on
Table 4.3 following this text.
4.5.2 Production Requirements
Mine production requirements for purposes of this study are based on
estimated fuel needs of the Colstrip Station, as provided by R. W. Beck*, and
anticipated sales to other customers, exclusive of tonnage committed to
Minnesota Power in July 1999. That customer base is assumed to remain constant
through year 2030 (i.e., coal contracts are assumed to be renewed). Resulting
production requirements for the Rosebud Mine over the 1999 through 2030
timeframe are 319 million tons, as shown below:
TOTAL AVG. PER YEAR
TONS (000) TONS (000)
---------- -------------
Colstrip Units 1 & 2................................ 93,960 2,983
Colstrip Units 3 & 4................................ 218,805 6,946
CELP Power Station*................................. 7,875 250
Great Lakes Terminal................................ 6,300 200
------- ------
319,065 10,129
- ---------------
* Waste coal -- not included in totals.
The projected annual coal production tonnage for the Colstrip station
reflects the fuel requirements provided by R. W. Beck, adjusted based on the
thermal content (Btu/lb) of the coal produced from each mine area over the study
period.
Other assumed purchasers of Rosebud production include the CELP Power
Station (which consumes waste coal) at 250,000 tons per year and industrial
sales (Great Lakes) at 200,000 tons per year. "Waste" coal supplied to the CELP
Power Station is selectively removed from the upper 6 inches of the Rosebud seam
in conjunction with Area C operations supplying Colstrip Units 3 & 4.
Coal for the Great Lakes Terminal is mined along with production for the
Colstrip Units 1 & 2 from Areas A, B, and D.
Additional coal is produced as feedstock for the ACCP plant. Current plans
are to mine that coal from Area A, although it could also come from Area C or D.
For purposes of this study, we have assumed that any ACCP coal mined from Area C
or D would be offset by synfuel sold to Units 1 & 2 and thus not impact overall
production requirements. The ACCP operation will most likely close in 2007 when
available tax credits end.
4.5.3 Mining Sequence and Schedule
The mining sequence is designed to advance from lower to higher strip ratio
areas. The sequence to supply Colstrip Units 1 & 2 continues current operations
in Area D until reserves are depleted in 2011, then moves to Mine Areas A and B.
- ---------------
* R. W. Beck provided the following fuel requirements for planning purposes:
-- Corette Station: 810,000 Tons per Year at 8,330 Btu/lb.
-- Colstrip Units 1 & 2: 3,020,000 tons per year at 8,558 Btu/lb.
-- Colstrip Units 3 & 4: 6,971,000 tons per year at 8,509 Btu/lb.
These production assumptions are adjusted for variations in coal quality to
supply the required total Btu.
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311
The Units 1 & 2 mining schedule and total coal recovered is shown in detail
on Table 4.2 and summarized below:
UNITS 1 & 2 MINING
- ------------------------------------------------------
MINE YEARS COAL RECOVERED EFFECTIVE RATIO*
AREA OF MINING (TONS-000) BCY/TON
- ---- ----------- -------------- ----------------
D 1999 - 2011 40,190 5.7
B 2012 - 2019 25,316 6.3
A 2020 - 2022 9,400 6.8
B 2023 - 2030 25,354 9.7
------- ---
Total 100,260 7.0
- ---------------
* Effective stripping ratio includes dragline rehandle.
Coal supply to Colstrip Units 3 & 4 assumes continuation of mining in Area
C and subsequent relocation to mine Area F. Mine Area C encompasses a 4 mile by
9 mile area and is comprised of five sub-areas. All of these sub-areas are mined
concurrently, based on the "least cost" design concept. The schedule of mining
in Areas C and F is shown on Table 4.3 and summarized below:
UNITS 3 & 4 MINING
- ------------------------------------------------------
MINE YEARS COAL RECOVERED EFFECTIVE RATIO*
AREA OF MINING (TONS-000) BCY/TON
- ---- ----------- -------------- ----------------
C 1999 - 2019 142,905 5.0
F 2020 - 2030 75,900 6.0
------- ---
218,805 5.4
- ---------------
* Effective stripping ratio includes dragline rehandle.
These planned mining sequences are consistent with WECO's long-term
planning concept, but assume no outside sales (except as noted) and continuing
coal consumption by Colstrip at the estimated rates.
4.5.4 Mining Equipment
The mining equipment in the long-term plan is initially the same as
currently in use at the Rosebud Mine. As the operation advances into areas of
higher strip ratio and consequent increased overburden volumes, additional
mining equipment is purchased to supplement the present fleets.
The four existing draglines, one Marion 8200 and three Marion 8050s, are
projected as the primary stripping machines. Presently two of the draglines are
operated regularly, with a third operated intermittently. The use of the
draglines is projected to increase until all four machines are scheduled for
continuous operation in the late years of the mine plan.
The draglines are supported by a fleet of large dozers (CAT D11 class).
This fleet prepares an extended bench from which the draglines operate. The
annual quantity of overburden the dozers push gradually increases over the mine
life, and the dozer fleet is projected to expand through additional purchases
according to these overburden volume increases.
The combined dragline and dozer fleets move all overburden at depths less
than 180 feet. Where overburden depth exceeds 180 feet, the overheight material
is assumed to be handled by contract earthmovers. The overheight material is
approximately 2% of total overburden volume, and therefore the contract
operations are limited.
Coal loading methods and equipment types are projected to remain the same
as at present in WECO's mine plan and as extended to 2030. The two oldest
coal-loading shovels are scheduled for replacement, as is the fleet of coal
haulers. The present 120-ton and 160-ton coal haulers are assumed to be replaced
with 200-ton haulers. The number of coal haulers is also increased in later
years of the mine life as haul distances
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increase. Coal mining support fleets, including front-end loaders, drills, road
graders, and water trucks, are replaced at typical unit life. The number of
machines assigned to road maintenance is supplemented as haul distances
increase.
4.6 COST PROJECTIONS
4.6.1 Cost Estimating Parameters and Assumptions
Capital and operating costs are generally estimated based on cost history
at the Rosebud Mine. Where past costs may not be representative of planned
operations, typical industry cost parameters are applied. For estimating
purposes, costs are expressed on a functional unit basis (i.e., $/BCY for
overburden removal, $/ton-mile for coal hauling, etc.).
Total mining costs are directly related to the material volumes (overburden
and coal) moved in each year of the plan. Inasmuch as overburden volume
increases gradually over the plan life, production costs increase
correspondingly. Major cost estimating parameters and assumptions in the plan
are:
- Present coal sales tonnages are assumed to continue beyond expiration of
the current contracts.
- Current mining equipment types (draglines, dozers, shovels, etc.) will be
used for future mining. No major new technologies are envisioned,
although certain upgrades are incorporated.
- Mining equipment application will continue as at present. Primarily, the
overburden stripping will include dozer pre-bench and dragline extended
bench operations.
- Stripping and loading equipment productivities remain constant over the
plan term.
- Capital expenditures for mining equipment replacement are scheduled based
on typical industry machine life.
- Rebuild capital has been included for the draglines and coal-loading
shovels at typical intervals in the life cycle of these machines.
- Coal haulage costs reflect the addition of larger capacity coal haulers
and greater efficiency related to longer haul distances.
- Projected operating costs include accruals to fund final reclamation of
the mines. These accruals are reflected in fuel costs only to the extent
allowed by the existing supply agreements.
All costs are projected in 4th quarter 1998 dollars with no allowance for
inflation. Costs include the direct cash cost for mine operations along with
estimated capital expenditures. The estimates presented in this chapter do not
include royalties, production taxes, and non-cash costs such as depreciation and
depletion.
The impact on overall mine costs resulting from the additional 1.5 MTPY
sold to Minnesota Power has not been quantified. We expect the overall effect on
a per-ton basis to be limited to reductions in certain fixed cost components,
and possibly some additional capital expenditures. We cannot reliably estimate
these cost impacts at this time; however, we do not believe overall mine costs
on a per-ton basis would change substantially from estimates presented herein.
4.6.2 Operating Cost Estimates
Operating costs are projected individually for the Units 1 & 2 coal supply
(Areas A, B, and D) and for operations supplying Colstrip Units 3 & 4 (Areas C
and F and the conveyor).
4-9
313
Estimated operating costs over the 1999 through 2030 study period are shown
in detail on Tables 4.2, 4.3, and 4.4 at the end of this chapter and are
summarized below:
MINING COST -- 1998 $ PER TON
---------------------------------------------------------------
THROUGH EXTENDED
CONTRACT THROUGH
MINE/OPERATION 1999 2000 2001 2002 TERM* 2030 AVERAGE
- -------------- ---- ---- ---- ---- -------- -------- -------
Units 1 & 2 (Areas A, B & D)
Overburden Removal................ 1.71 1.69 1.37 1.12 1.65 2.27 2.03
Coal Mining....................... 1.06 0.95 1.02 1.05 1.01 1.13 1.09
Reclamation....................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37
Other............................. 1.33 1.33 1.33 1.33 1.33 1.33 1.34
---- ---- ---- ---- ---- ---- ----
Total -- 1 & 2.......... 4.47 4.34 4.10 3.87 4.36 5.12 4.84
Units 3 & 4 (Areas C & F)
Overburden Removal................ 0.76 0.60 0.61 0.62 1.59 1.75 1.54
Coal Mining....................... 1.08 1.12 1.22 1.26 1.10 1.59 1.28
Reclamation....................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37
Other............................. 1.36 1.29 1.29 1.29 1.29 1.30 1.29
---- ---- ---- ---- ---- ---- ----
Subtotal................... 3.56 3.38 3.49 3.54 4.35 5.01 4.48
Conveyor.......................... 0.22 0.22 0.22 0.22 0.22 0.22 0.22
---- ---- ---- ---- ---- ---- ----
Total -- 3 & 4.......... 3.78 3.60 3.71 3.76 4.57 5.23 4.70
- ---------------
* 2003 through 2009 for Units 1 & 2, and 2003 through 2019 for Units 3 & 4.
Operating costs gradually increase over the plan period, reflecting the
advance of operations into higher strip ratio reserves. Conveying costs remain
essentially constant over the plan term; however, truck haulage costs (included
in "Coal Mining") increase somewhat as haul distances increase.
4.6.3 Capital Costs
Projected capital expenditures in the plan total $242 million over the 1999
through 2030 term. Capital costs by mine area are shown on Tables 4.2, 4.3, and
4.4, and summarized below:
CAPITAL EXPENDITURES ($-000)
--------------------------------------
UNITS 1 & 2 UNITS 3 & 4 CONVEYOR
(A, B, & D) (C & F) SYSTEM
----------- ----------- --------
Site Preparation................................... 3,185 5,262 0
Buildings & Infrastructure......................... 6,375 11,186 0
Mining Equipment................................... 69,285 113,965 6,990
Support Equipment.................................. 8,065 17,936 0
------ ------- -----
Total.................................... 86,910 148,349 6,990
The majority of capital expenditures (almost 80% of total) are for mining
equipment replacement, rebuilds, and fleet expansion. Due to the age of much of
the existing equipment, significant capital expenditures, approximately $67
million (28% of total), are scheduled between 1999 and 2005. These expenditures
are considered necessary to maintain mine productivity and assure fuel supply
reliability.
Actual capital expenditures for 1999 are, based on conversations with WECO
personnel, reasonably consistent with projections. Exceptions are the
acquisition of the federal coal leases, which was more costly than planned ($4.4
million vs. $4.0 million), and certain new equipment, which will be leased
rather than purchased. Other planned capital purchases are in process, but may
not be completed in 1999.
4-10
314
4.7 GENERAL COMMENTS
The Rosebud Mine has been producing coal for the Colstrip Power Station for
over 20 years and is a proven reliable fuel source. In BOYD's opinion, the mine
is capable of continuing to supply contracted fuel supplies through the term of
the current contracts. The age of current mining equipment fleets is a concern,
and significant capital expenditures in an equipment upgrade program are planned
for and incorporated in cost projections herein.
There are areas of risk or uncertainty relative to mine operations and
costs. These include:
- Renegotiation of hourly workers' collective bargaining agreements in
2001.
- Leasing of federal reserves in Area C.
- Higher sodium content coals in Areas D and F that may require blending.
- Permitting issues related to probable hydrologic consequences of mining
in Area C.
We do not consider any of these uncertainties as likely to significantly affect
the fuel supply.
Projections beyond the current contract terms to 2030 are more speculative.
While there is no guarantee, we consider it likely that adequate reserves and
resources will be available and that the mine will be capable of continuing to
supply coal at costs and volumes projected.
Beyond 2030, the remaining available coal resources will be higher ratio
"extended resources" which would be relatively expensive to mine. We consider it
likely that lower cost fuel would be available from other sources (specifically
the SPRB) at that time, and that Rosebud operations will cease.
Following this text are:
Tables:
4.1: Historical Performance Summary
4.2: Mine Plan and Cost Estimate -- Units 1 & 2
4.3: Mine Plan and Cost Estimate -- Units 3 & 4
4.4: Conveyor Operating Cost Estimate
4-11
315
TABLE 4.1
HISTORICAL PERFORMANCE SUMMARY
ROSEBUD MINE
ROSEBUD COUNTY, MONTANA
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
1995 1996 1997 1998 AVERAGE
------- ------- ------- ------ ---------
PRODUCTION (TONS SOLD - 000):
Area A.................................... 345 -- -- -- 86
Area B.................................... 2,087 -- -- -- 522
Area C.................................... 5,546 4,365 6,200 7,275 5,847
Area D.................................... 3,271 3,414 2,927 3,224 3,209
------- ------- ------- ------ -------
Total........................... 11,249 7,779 9,127 10,499 9,664
QUALITY (AS RECEIVED):
Area C
Moisture (%)............................ 25.88 25.90 25.72 25.80 25.82
Ash (%)................................. 9.64 9.75 9.89 9.95 9.82
Sulfur (%).............................. 0.70 0.76 0.77 0.75 0.75
BTU/lb.................................. 8,509 8,512 8,543 8,514 8,520
Area D
Moisture (%)............................ 25.92 26.23 26.32 26.41 26.22
Ash (%)................................. 8.44 8.57 8.98 9.03 8.75
Sulfur (%).............................. 0.68 0.71 0.76 0.73 0.72
BTU/lb.................................. 8,630 8,546 8,491 8,474 8,537
STRIPPING OPERATIONS:
Area B
Overburden:
Virgin (BCY-000)........................ 8,865 -- -- -- 2,216
Rehandle (BCY-000)...................... 1,468 -- -- -- 367
------- ------- ------- ------ -------
Total........................... 10,333 -- -- -- 2,583
Stripping Ratio:
Virgin (BCY/ton)........................ 4.25 -- -- -- 4.25
Effective (BCY/ton)..................... 4.95 -- -- -- 4.95
Area C
Overburden:
Virgin (BCY-000)........................ 19,266 14,682 17,597 26,156 19,425
Rehandle (BCY-000)...................... 3,993 2,079 1,566 3,832 2,868
------- ------- ------- ------ -------
Total........................... 23,259 16,761 19,163 29,988 22,293
Stripping Ratio:
Virgin (BCY/ton)........................ 3.47 3.36 2.84 3.60 3.32
Effective (BCY/ton)..................... 4.19 3.84 3.09 4.12 3.81
4-12
316
1995 1996 1997 1998 AVERAGE
------- ------- ------- ------ ---------
Area D
Overburden:
Virgin (BCY-000)........................ 9,206 11,782 10,114 12,329 10,858
Rehandle (BCY-000)...................... 1,206 1,118 766 932 1,006
------- ------- ------- ------ -------
Total........................... 10,412 12,900 10,880 13,261 11,863
Stripping Ratio:
Virgin (BCY/ton)........................ 2.81 3.45 3.46 3.82 3.38
Effective (BCY/ton)..................... 3.18 3.78 3.72 4.11 3.70
All Areas
Overburden:
Virgin (BCY-000)........................ 37,337 26,464 27,711 38,485 32,499
Rehandle (BCY-000)...................... 6,667 3,197 2,332 4,764 4,240
------- ------- ------- ------ -------
Total........................... 44,004 29,661 30,043 43,249 36,739
Stripping Ratio:
Virgin (BCY/ton)........................ 3.32 3.40 3.04 3.67 3.36
Effective (BCY/ton)..................... 3.91 3.81 3.29 4.12 3.80
1995 1996 1997 1998 TOTAL/AVG.
------- ------- ------- ------ ----------
LABOR FORCE:
Employees
Salaried................................ n/a n/a 78 77 78
Hourly:
Mine................................. n/a n/a 161 188 175
Conveyor............................. n/a n/a 12 13 13
ACCP................................. n/a n/a 24 22 23
------- ------- ------- ------ -------
Subtotal........................ n/a n/a 197 223 210
Total(1)........................ 355 268 275 300 288
Employee Hrs Worked
All Mine Employees...................... 653,054 n/a n/a n/a 653,054
Reported to MSHA........................ 700,673 518,068 547,292 n/a 588,678
Labor Productivity
Tons/Empl. Hr. (All).................... 16.05 15.02 16.68 n/a 15.92
Tons/E-Hr. (MSHA)....................... 16.61 14.94 16.67 n/a 16.07
CASH OPERATING COSTS:(2)
Direct Mining Expense ($/ton)
Overburden Removal................... n/a 1.29 0.92 1.16 1.12
Coal Loading & Hauling............... n/a 1.20 0.82 0.78 0.91
Reclamation.......................... n/a 0.89 0.40 0.25 0.48
Crushing/Conveying................... n/a 0.40 0.34 0.29 0.34
Supervision/Engineering.............. n/a 0.50 0.28 0.28 0.34
Other................................ n/a 0.23 0.30 0.30 0.28
------- ------- ------- ------ -------
Subtotal........................ n/a 4.51 3.04 3.07 3.47
4-13
317
1995 1996 1997 1998 TOTAL/AVG.
------- ------- ------- ------ ----------
Other Expenses ($/ton)
Lease Rent & Records................. n/a 0.02 0.01 0.01 0.01
A & G and Overheads.................. n/a 1.67 0.85 0.65 1.01
------- ------- ------- ------ -------
Subtotal........................ n/a 1.69 0.86 0.66 1.02
I -- Cash Operating Cost.................. n/a 6.20 3.90 3.72 4.49
- ---------------
Notes: (1) Data for 1995 and 1996 are based on MSHA reports and are excluded
from the average.
(2) Cost data excludes royalties, taxes and non-cash costs. Cost data for
1996 is based on management control report information which has not
been verified. Cost data for 1998 is through November.
4-14
318
TABLE 4.2
MINE PLAN AND COST ESTIMATE
ROSEBUD MINE -- UNITS 1 & 2 (AREAS A, B & D)
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
- -------------------------- ----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000).... 8,185 16,048 13,783 11,693 11,379 12,133 11,399 11,936 19,597 20,435 21,702
Contract Pre-Bench Volume
(Bcy-000).................... 8 152 43 -- 104 77 17 93 323 189 877
Dozer Pre-Bench Volume
(Bcy-000).................... 2,191 4,470 2,293 997 1,823 1,933 991 2,293 6,515 6,142 8,288
Dragline Strip Volume:
Virgin (Bcy-000)............. 5,986 11,426 11,447 10,696 9,452 10,123 10,391 9,551 12,759 14,104 12,537
Rehandle (Bcy-000)........... 1,679 3,043 1,791 973 1,287 1,451 905 1,539 4,002 4,226 5,066
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Dragline............... 7,664 14,469 13,238 11,669 10,739 11,574 11,297 11,090 16,761 18,330 17,603
Total Effective Overburden
(Bcy-000).................. 9,863 19,091 15,574 12,666 12,666 13,584 12,304 13,475 23,599 24,661 26,768
COAL PRODUCTION
COAL RECOVERED (TONS-000):
Area D......................... 1,610 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220
Area A (Supplemental
Reserves).................... -- -- -- -- -- -- -- -- -- -- --
Area B (Supplemental
Reserves).................... -- -- -- -- -- -- -- -- -- -- --
Area B (Extended Resources).... -- -- -- -- -- -- -- -- -- -- --
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total........................ 1,610 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220
Virgin Strip Ratio (Bcy/Rec.
Ton)......................... 5.08 4.98 4.28 3.63 3.53 3.77 3.54 3.71 6.09 6.35 6.74
Effective Strip Ratio (Bcy/Rec.
Ton)......................... 6.13 5.93 4.84 3.93 3.93 4.22 3.82 4.18 7.33 7.66 8.31
One-way haul distance
(miles)...................... 3.0 3.0 3.8 4.0 3.9 3.6 3.7 3.4 3.7 3.7 3.5
PRODUCT COAL QUALITY (AS RECD):
Ash (%)........................ 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10 8.10
Sulfur (%)..................... 0.64 0.64 0.64 0.64 0.64 0.64 0.64 0.64 0.64 0.64 0.64
Btu/Lb......................... 8,558 8,558 8,558 8,558 8,558 8,558 8,558 8,558 8,558 8,558 8,558
Na2O in Ash (%)................ 0.40 0.40 0.42 0.44 0.45 0.46 0.47 0.46 0.41 0.57 1.01
COAL SALES (TONS-000):
Customer #4 -- Great Lakes..... 100 200 200 200 200 200 200 200 200 200 200
Customer #5 -- Colstrip #1 &
#2........................... 1,510 3,020 3,020 3,020 3,020 3,020 3,020 3,020 3,020 3,020 3,020
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Coal Tonnage........... 1,610 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220 3,220
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000).... 22,790 18,392 13,539 14,833 16,448 17,056
Contract Pre-Bench Volume
(Bcy-000).................... 1,127 225 -- -- 8 --
Dozer Pre-Bench Volume
(Bcy-000).................... 9,270 5,939 2,128 3,409 5,018 5,633
Dragline Strip Volume:
Virgin (Bcy-000)............. 12,393 12,229 11,411 11,424 11,422 11,423
Rehandle (Bcy-000)........... 5,317 4,237 2,424 3,364 3,957 4,216
------ ------ ------ ------ ------ ------
Total Dragline............... 17,711 16,466 13,835 14,788 15,380 15,639
Total Effective Overburden
(Bcy-000).................. 28,107 22,629 15,963 18,197 20,406 21,273
COAL PRODUCTION
COAL RECOVERED (TONS-000):
Area D......................... 3,220 3,160 -- -- -- --
Area A (Supplemental
Reserves).................... -- -- -- -- -- --
Area B (Supplemental
Reserves).................... -- 60 3,157 3,157 3,157 3,157
Area B (Extended Resources).... -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total........................ 3,220 3,220 3,157 3,157 3,157 3,157
Virgin Strip Ratio (Bcy/Rec.
Ton)......................... 7.08 5.71 4.29 4.70 5.21 5.40
Effective Strip Ratio (Bcy/Rec.
Ton)......................... 8.73 7.03 5.06 5.76 6.46 6.74
One-way haul distance
(miles)...................... 2.9 3.4 5.7 5.5 4.9 6.1
PRODUCT COAL QUALITY (AS RECD):
Ash (%)........................ 8.10 8.10 8.85 8.85 8.85 8.85
Sulfur (%)..................... 0.64 0.64 0.72 0.72 0.72 0.72
Btu/Lb......................... 8,558 8,558 8,740 8,740 8,740 8,740
Na2O in Ash (%)................ 1.38 1.35 0.30 0.30 0.30 0.30
COAL SALES (TONS-000):
Customer #4 -- Great Lakes..... 200 200 200 200 200 200
Customer #5 -- Colstrip #1 &
#2........................... 3,020 3,020 2,957 2,957 2,957 2,957
------ ------ ------ ------ ------ ------
Total Coal Tonnage........... 3,220 3,220 3,157 3,157 3,157 3,157
4-15
319
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
- -------------------------- ----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting............ 818 1,606 1,381 1,173 1,142 1,219 1,147 1,202 1,975 2,062 2,192
Contract Pre-Bench............. 7 137 38 -- 94 70 15 84 293 172 797
Dozer Pre-Bench................ 460 940 482 210 384 408 209 485 1,379 1,301 1,758
Dragline Stripping............. 1,380 2,607 2,388 2,107 1,941 2,094 2,046 2,010 3,041 3,329 3,200
Misc. Overburden Removal....... 82 161 138 117 114 122 115 120 198 206 219
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000).................... 2,747 5,450 4,428 3,607 3,676 3,913 3,531 3,901 6,886 7,070 8,166
COAL MINING OPERATIONS:
Drilling & Blasting............ 113 225 225 225 225 225 225 225 225 225 225
Coal Cleaning.................. 64 129 129 129 129 129 129 129 129 129 129
Coal Loading/Pit Pumping....... 337 674 674 674 674 674 674 674 674 674 674
Coal Haulage & Roads........... 925 1,469 1,719 1,808 1,773 1,667 1,693 1,597 1,693 1,703 1,642
Stockpile and Crushing......... 274 547 547 547 547 547 547 547 547 547 547
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000).................... 1,712 3,044 3,294 3,384 3,348 3,243 3,268 3,172 3,268 3,278 3,217
RECLAMATION OPERATIONS:
Ongoing Reclamation............ 451 902 902 902 902 902 902 902 902 902 902
Final Reclamation Accrual...... 145 290 290 290 290 290 290 290 290 290 290
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Reclamation Cost
($-000).................... 596 1,191 1,191 1,191 1,191 1,191 1,191 1,191 1,191 1,191 1,191
OTHER EXPENSES:
Power Systems Maintenance...... 32 63 63 63 63 63 63 63 63 63 63
Supervisory/Engineering........ 450 900 900 900 900 900 900 900 900 900 900
Warehouse/Inventory............ 93 186 186 186 186 186 186 186 186 186 186
Unallocated Maintenance........ 354 708 708 708 708 708 708 708 708 708 708
Lease Rent & Records........... 16 32 32 32 32 32 32 32 32 32 32
A & G and Overheads............ 1,200 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Other Cost ($-000)..... 2,145 4,290 4,290 4,290 4,290 4,290 4,290 4,290 4,290 4,290 4,290
TOTAL OPERATING COST
($-000).................... 7,200 13,976 13,203 12,471 12,505 12,637 12,281 12,554 15,636 15,829 16,865
MINE COST BY FUNCTION ($/TON)
Overburden Removal............. 1.71 1.69 1.38 1.12 1.14 1.22 1.10 1.21 2.14 2.20 2.54
Coal Mining.................... 1.06 0.95 1.02 1.05 1.04 1.01 1.02 0.99 1.02 1.02 1.00
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses................. 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33 1.33
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total........................ 4.47 4.34 4.10 3.87 3.88 3.92 3.81 3.90 4.86 4.92 5.24
MINE COST BY CATEGORY ($/TON)
Labor.......................... 1.23 1.18 1.13 1.07 1.07 1.08 1.05 1.07 1.33 1.35 1.42
Power.......................... 0.39 0.37 0.35 0.32 0.30 0.32 0.31 0.31 0.43 0.45 0.45
Materials & Supplies........... 1.73 1.66 1.50 1.36 1.39 1.40 1.33 1.40 1.98 1.99 2.24
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37
A & G and Overheads............ 0.76 0.76 0.76 0.76 0.76 0.76 0.76 0.76 0.76 0.76 0.76
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total ($/Ton)................ 4.47 4.34 4.10 3.87 3.88 3.92 3.81 3.90 4.86 4.92 5.24
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting............ 2,304 1,861 1,371 1,504 1,669 1,733
Contract Pre-Bench............. 1,025 205 -- -- 8 --
Dozer Pre-Bench................ 1,968 1,262 453 726 1,070 1,202
Dragline Stripping............. 3,223 2,999 2,523 2,699 2,810 2,860
Misc. Overburden Removal....... 230 186 137 150 167 173
------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000).................... 8,751 6,513 4,484 5,079 5,723 5,968
COAL MINING OPERATIONS:
Drilling & Blasting............ 225 225 221 221 221 221
Coal Cleaning.................. 129 129 126 126 126 126
Coal Loading/Pit Pumping....... 674 674 662 662 662 662
Coal Haulage & Roads........... 1,427 1,603 2,117 2,061 1,891 2,231
Stockpile and Crushing......... 547 547 537 537 537 537
------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000).................... 3,003 3,179 3,663 3,607 3,437 3,776
RECLAMATION OPERATIONS:
Ongoing Reclamation............ 902 902 884 884 884 884
Final Reclamation Accrual...... 290 290 284 284 284 284
------ ------ ------ ------ ------ ------
Total Reclamation Cost
($-000).................... 1,191 1,191 1,168 1,168 1,168 1,168
OTHER EXPENSES:
Power Systems Maintenance...... 63 63 63 63 63 63
Supervisory/Engineering........ 900 900 900 900 900 900
Warehouse/Inventory............ 186 186 186 186 186 186
Unallocated Maintenance........ 708 708 695 695 695 695
Lease Rent & Records........... 32 32 32 32 32 32
A & G and Overheads............ 2,400 2,400 2,400 2,400 2,400 2,400
------ ------ ------ ------ ------ ------
Total Other Cost ($-000)..... 4,290 4,290 4,275 4,275 4,275 4,275
TOTAL OPERATING COST
($-000).................... 17,235 15,173 13,590 14,129 14,604 15,188
MINE COST BY FUNCTION ($/TON)
Overburden Removal............. 2.72 2.02 1.42 1.61 1.81 1.89
Coal Mining.................... 0.93 0.99 1.16 1.14 1.09 1.20
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses................. 1.33 1.33 1.35 1.35 1.35 1.35
------ ------ ------ ------ ------ ------
Total........................ 5.35 4.71 4.30 4.48 4.63 4.81
MINE COST BY CATEGORY ($/TON)
Labor.......................... 1.45 1.29 1.20 1.24 1.27 1.33
Power.......................... 0.45 0.42 0.36 0.38 0.40 0.41
Materials & Supplies........... 2.33 1.88 1.60 1.71 1.81 1.93
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37
A & G and Overheads............ 0.76 0.76 0.77 0.77 0.77 0.77
------ ------ ------ ------ ------ ------
Total ($/Ton)................ 5.35 4.71 4.30 4.48 4.63 4.81
4-16
320
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
- -------------------------- ----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
TOTAL CAPITAL EXPENDITURES
($-000):
Site Preparation............... 100 525 260 -- -- -- -- -- -- -- --
Buildings & Infrastructure..... 80 80 580 80 155 80 80 80 80 80 80
Mining Equipment............... 400 5,000 7,200 2,940 955 955 955 955 955 955 1,305
Support Equipment.............. 210 390 210 360 210 260 390 210 210 260 210
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Capital ($-000)........ 790 5,995 8,250 3,380 1,320 1,295 1,425 1,245 1,245 1,295 1,595
Depreciation $/Yr (000)........ 1,900 2,194 2,331 2,396 2,545 2,535 2,518 2,627 2,662 2,604 2,589
$/Ton.......................... 1.18 0.68 0.72 0.74 0.79 0.79 0.78 0.82 0.83 0.81 0.80
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
TOTAL CAPITAL EXPENDITURES
($-000):
Site Preparation............... 900 850 -- -- -- --
Buildings & Infrastructure..... 580 330 580 80 80 80
Mining Equipment............... 10,155 2,905 6,390 955 3,755 3,755
Support Equipment.............. 390 210 360 210 260 390
------ ------ ------ ------ ------ ------
Total Capital ($-000)........ 12,025 4,295 7,330 1,245 4,095 4,225
Depreciation $/Yr (000)........ 2,943 3,334 3,604 3,757 3,811 3,855
$/Ton.......................... 0.91 1.04 1.14 1.19 1.21 1.22
- ---------------
Note: Projections based on data from January 1999
4-17
321
TABLE 4.2 -- (CONTINUED)
MINE PLAN AND COST ESTIMATE
ROSEBUD MINE -- UNITS 1 & 2 (AREAS A, B & D)
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)...... 17,605 16,288 17,262 17,337 16,406 18,277 18,443 22,617 22,617 24,029 24,029
Contract Pre-Bench Volume
(Bcy-000)...................... 188 57 -- 146 58 119 453 -- -- -- --
Dozer Pre-Bench Volume
(Bcy-000)...................... 5,993 4,806 5,839 5,733 4,184 5,591 6,732 9,895 9,895 11,308 11,308
Dragline Strip Volume:
Virgin (Bcy-000)................. 11,424 11,425 11,423 11,459 12,163 12,566 11,258 12,722 12,722 12,722 12,722
Rehandle (Bcy-000)............. 4,260 3,931 4,303 4,176 3,181 4,042 4,364 5,788 5,788 6,081 6,081
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Dragline................. 15,684 15,357 15,726 15,634 15,344 16,608 15,622 18,510 18,510 18,803 18,803
Total Effective Overburden
(Bcy-000).................... 21,865 20,220 21,565 21,513 19,586 22,319 22,807 28,405 28,405 30,111 30,111
COAL PRODUCTION
Coal Recovered (Tons-000):
Area D........................... -- -- -- -- -- -- -- -- -- -- --
Area A (Supplemental Reserves)... -- -- -- -- 3,166 3,166 3,068 -- -- -- --
Area B (Supplemental Reserves)... 3,157 3,157 3,157 3,157 -- -- -- -- -- -- --
Area B (Extended Resources)...... -- -- -- -- -- -- 98 3,157 3,157 3,157 3,157
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total.......................... 3,157 3,157 3,157 3,157 3,166 3,166 3,166 3,157 3,157 3,157 3,157
Virgin Strip Ratio (Bcy/Rec.
Ton)........................... 5.58 5.16 5.47 5.49 5.18 5.77 5.83 7.16 7.16 7.61 7.61
Effective Strip Ratio (Bcy/Rec.
Ton)........................... 6.93 6.40 6.83 6.81 6.19 7.05 7.20 9.00 9.00 9.54 9.54
One-way haul distance (miles).... 4.9 3.6 5.7 4.3 7.5 7.5 7.5 5.5 5.5 5.6 5.6
PRODUCT COAL QUALITY (AS RECD):
Ash (%).......................... 8.85 8.85 8.85 8.85 8.91 8.91 8.91 8.85 8.85 8.85 8.85
Sulfur (%)....................... 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72 0.72
Btu/Lb. ......................... 8,740 8,740 8,740 8,740 8,713 8,713 8,713 8,740 8,740 8,740 8,740
Na2O in Ash (%).................. 0.30 0.30 0.30 0.30 0.54 0.54 0.54 0.30 0.30 0.30 0.30
COAL SALES (TONS-000):
Customer #4 -- Great Lakes....... 200 200 200 200 200 200 200 200 200 200 200
Customer #5 -- Colstrip #1 &
#2............................. 2,957 2,957 2,957 2,957 2,966 2,966 2,966 2,957 2,957 2,957 2,957
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Coal Tonnage............. 3,157 3,157 3,157 3,157 3,166 3,166 3,166 3,157 3,157 3,157 3,157
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting.............. 1,790 1,658 1,759 1,768 1,675 1,868 1,887 2,316 2,318 2,465 2,468
Contract Pre-Bench............... 172 52 -- 134 53 110 417 -- -- -- --
Dozer Pre-Bench.................. 1,280 1,027 1,249 1,228 897 1,200 1,446 2,128 2,130 2,436 2,439
Dragline Stripping............... 2,871 2,814 2,884 2,870 2,820 3,055 2,877 3,412 3,415 3,472 3,476
Misc. Overburden Removal......... 179 166 176 177 168 187 189 232 232 247 247
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000)...................... 6,293 5,718 6,069 6,177 5,613 6,420 6,815 8,087 8,095 8,621 8,629
2027 2028 2029 2030 TOTAL
------ ------ ------ ------ -------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)...... 24,029 25,443 25,443 26,857 578,030
Contract Pre-Bench Volume
(Bcy-000)...................... -- -- -- 1,414 5,677
Dozer Pre-Bench Volume
(Bcy-000)...................... 11,308 12,722 12,722 12,722 200,087
Dragline Strip Volume:
Virgin (Bcy-000)................. 12,722 12,722 12,722 12,722 372,266
Rehandle (Bcy-000)............. 6,081 6,297 6,297 6,297 126,445
------ ------ ------ ------ -------
Total Dragline................. 18,803 19,019 19,019 19,019 498,711
Total Effective Overburden
(Bcy-000).................... 30,111 31,740 31,740 33,154 704,474
COAL PRODUCTION
Coal Recovered (Tons-000):
Area D........................... -- -- -- -- 40,190
Area A (Supplemental Reserves)... -- -- -- -- 9,400
Area B (Supplemental Reserves)... -- -- -- -- 25,316
Area B (Extended Resources)...... 3,157 3,157 3,157 3,157 25,354
------ ------ ------ ------ -------
Total.......................... 3,157 3,157 3,157 3,157 100,260
Virgin Strip Ratio (Bcy/Rec.
Ton)........................... 7.61 8.06 8.06 8.51 5.77
Effective Strip Ratio (Bcy/Rec.
Ton)........................... 9.54 10.05 10.05 10.50 7.03
One-way haul distance (miles).... 5.7 5.7 5.8 5.8
PRODUCT COAL QUALITY (AS RECD):
Ash (%).......................... 8.85 8.85 8.85 8.85
Sulfur (%)....................... 0.72 0.72 0.72 0.72
Btu/Lb. ......................... 8,740 8,740 8,740 8,740
Na2O in Ash (%).................. 0.30 0.30 0.30 0.30
COAL SALES (TONS-000):
Customer #4 -- Great Lakes....... 200 200 200 200 6,300
Customer #5 -- Colstrip #1 &
#2............................. 2,957 2,957 2,957 2,957 93,960
------ ------ ------ ------ -------
Total Coal Tonnage............. 3,157 3,157 3,157 3,157 100,260
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting.............. 2,470 2,618 2,621 2,769 58,813
Contract Pre-Bench............... -- -- -- 1,312 5,195
Dozer Pre-Bench.................. 2,441 2,749 2,752 2,754 42,854
Dragline Stripping............... 3,479 3,523 3,526 3,530 91,280
Misc. Overburden Removal......... 247 262 262 277 5,881
------ ------ ------ ------ -------
Total Overburden Cost
($-000)...................... 8,638 9,152 9,160 10,642 204,023
4-18
322
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
COAL MINING OPERATIONS:
Drilling & Blasting.............. 221 221 221 221 222 222 222 221 221 221 221
Coal Cleaning.................... 126 126 126 126 127 127 127 126 126 126 126
Coal Loading/Pit Pumping......... 662 662 662 662 664 664 664 662 662 662 662
Coal Haulage & Roads............. 1,891 1,635 2,117 1,721 2,401 2,401 2,401 2,061 2,061 2,089 2,089
Stockpile and Crushing........... 537 537 537 537 538 538 538 537 537 537 537
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000)...................... 3,437 3,181 3,663 3,267 3,951 3,951 3,951 3,607 3,607 3,635 3,635
RECLAMATION OPERATIONS:
Ongoing Reclamation.............. 884 884 884 884 886 886 886 884 884 884 884
Final Reclamation Accrual........ 284 284 284 284 285 285 285 284 284 284 284
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Reclamation Cost
($-000)...................... 1,168 1,168 1,168 1,168 1,171 1,171 1,171 1,168 1,168 1,168 1,168
OTHER EXPENSES:
Power Systems Maintenance........ 63 63 63 63 63 63 63 63 63 63 63
Supervisory/Engineering.......... 900 900 900 900 900 900 900 900 900 900 900
Warehouse/Inventory.............. 186 186 186 186 186 186 186 186 186 186 186
Unallocated Maintenance.......... 695 695 695 695 697 697 697 695 695 695 695
Lease Rent & Records............. 32 32 32 32 32 32 32 32 32 32 32
A & G and Overheads.............. 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Other Cost ($-000)....... 4,275 4,275 4,275 4,275 4,277 4,277 4,277 4,275 4,275 4,275 4,275
TOTAL OPERATING COST ($-000)... 15,173 14,341 15,175 14,888 15,013 15,820 16,215 17,137 17,145 17,699 17,707
MINE COST BY FUNCTION ($/TON)
Overburden Removal............... 1.99 1.81 1.92 1.96 1.77 2.03 2.15 2.56 2.56 2.73 2.73
Coal Mining...................... 1.09 1.01 1.16 1.03 1.25 1.25 1.25 1.14 1.14 1.15 1.15
Reclamation...................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses................... 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35 1.35
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total.......................... 4.81 4.54 4.81 4.72 4.74 5.00 5.12 5.43 5.43 5.61 5.61
MINE COST BY CATEGORY ($/TON)
Labor............................ 1.32 1.25 1.33 1.29 1.32 1.39 1.42 1.49 1.49 1.54 1.54
Power............................ 0.41 0.40 0.41 0.41 0.40 0.43 0.41 0.48 0.48 0.49 0.49
Materials & Supplies............. 1.94 1.76 1.93 1.87 1.88 2.04 2.15 2.32 2.32 2.44 2.44
Reclamation...................... 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37 0.37
A & G and Overheads.............. 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total ($/Ton).................. 4.81 4.54 4.81 4.72 4.74 5.00 5.12 5.43 5.43 5.61 5.61
TOTAL CAPITAL EXPENDITURES
($-000):
Site Preparation................. -- -- -- -- 550 -- -- -- -- -- --
Buildings & Infrastructure....... 2,080 80 80 155 80 80 80 80 80 80 80
Mining Equipment................. 955 1,305 2,155 955 3,405 3,955 1,090 655 655 655 2,205
Support Equipment................ 210 210 260 210 390 210 360 210 260 390 210
----- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Capital ($-000).......... 3,245 1,595 2,495 1,320 4,425 4,245 1,530 945 995 1,125 2,495
Depreciation $/Yr (000).......... 3,660 3,488 3,446 3,407 3,298 3,226 3,254 3,211 3,166 2,982 2,753
$/Ton............................ 1.16 1.10 1.09 1.08 1.04 1.02 1.03 1.02 1.00 0.94 0.87
2027 2028 2029 2030 TOTAL
------ ------ ------ ------ -------
COAL MINING OPERATIONS:
Drilling & Blasting.............. 221 221 221 221 7,018
Coal Cleaning.................... 126 126 126 126 4,010
Coal Loading/Pit Pumping......... 662 662 662 662 21,002
Coal Haulage & Roads............. 2,117 2,117 2,146 2,146 60,416
Stockpile and Crushing........... 537 537 537 537 17,044
------ ------ ------ ------ -------
Total Coal Mining Cost
($-000)...................... 3,663 3,663 3,692 3,692 109,491
RECLAMATION OPERATIONS:
Ongoing Reclamation.............. 884 884 884 884 28,073
Final Reclamation Accrual........ 284 284 284 284 9,023
------ ------ ------ ------ -------
Total Reclamation Cost
($-000)...................... 1,168 1,168 1,168 1,168 37,096
OTHER EXPENSES:
Power Systems Maintenance........ 63 63 63 63 1,985
Supervisory/Engineering.......... 900 900 900 900 28,350
Warehouse/Inventory.............. 186 186 186 186 5,859
Unallocated Maintenance.......... 695 695 695 695 22,057
Lease Rent & Records............. 32 32 32 32 1,003
A & G and Overheads.............. 2,400 2,400 2,400 2,400 75,600
------ ------ ------ ------ -------
Total Other Cost ($-000)....... 4,275 4,275 4,275 4,275 134,853
TOTAL OPERATING COST ($-000)... 17,744 18,258 18,295 19,776 485,463
MINE COST BY FUNCTION ($/TON)
Overburden Removal............... 2.74 2.90 2.90 3.37 2.03
Coal Mining...................... 1.16 1.16 1.17 1.17 1.09
Reclamation...................... 0.37 0.37 0.37 0.37 0.37
Other Expenses................... 1.35 1.35 1.35 1.35 1.35
------ ------ ------ ------ -------
Total.......................... 5.62 5.78 5.80 6.26 4.84
MINE COST BY CATEGORY ($/TON)
Labor............................ 1.54 1.58 1.59 1.70 1.33
Power............................ 0.49 0.50 0.50 0.51 0.41
Materials & Supplies............. 2.45 2.56 2.57 2.91 1.96
Reclamation...................... 0.37 0.37 0.37 0.37 0.37
A & G and Overheads.............. 0.77 0.77 0.77 0.77 0.76
------ ------ ------ ------ -------
Total ($/Ton).................. 5.62 5.78 5.80 6.26 4.84
TOTAL CAPITAL EXPENDITURES
($-000):
Site Preparation................. -- -- -- -- 3,185
Buildings & Infrastructure....... 155 80 -- -- 6,375
Mining Equipment................. 455 300 50 -- 69,285
Support Equipment................ 210 150 45 -- 8,065
------ ------ ------ ------ -------
Total Capital ($-000).......... 820 530 95 -- 86,910
Depreciation $/Yr (000).......... 2,479 2,207 1,972 1,551 92,307
$/Ton............................ 0.79 0.70 0.62 0.49 0.92
4-19
323
TABLE 4.3
MINE PLAN AND COST ESTIMATE
ROSEBUD MINE -- UNITS 3 & 4 FUEL SUPPLY (AREAS C & F)
FOR
CHASE SECURITIES, INC
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003
- -------------------------- ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)...... 9,075 14,515 14,673 14,803 15,628
Contract Pre-Bench Volume
(Bcy-000).................... -- -- -- -- --
Dozer Pre-Bench Volume
(Bcy-000).................... -- -- -- -- 207
Dragline Strip Volume:
Virgin (Bcy-000)............. 9,075 14,515 14,673 14,803 15,421
Rehandle (Bcy-000)........... -- -- -- -- 259
------ ------ ------ ------ ------
Total Dragline............. 9,075 14,515 14,673 14,803 15,680
Total Effective Overburden
(Bcy-000).................... 9,075 14,515 14,673 14,803 15,887
COAL PRODUCTION
Coal Recovered (Tons-000) Area
C............................ 3,485 6,971 6,971 6,971 6,971
Area F....................... -- -- -- -- --
------ ------ ------ ------ ------
Total...................... 3,485 6,971 6,971 6,971 6,971
Product Coal Quality (As-Recd):
Ash (%)........................ 9.27 9.27 9.33 9.41 9.41
Sulfur (%)..................... 0.68 0.68 0.69 0.68 0.68
Btu/Lb......................... 8,506 8,509 8,507 8,509 8,509
Na(2)O in Ash (%).............. 0.76 0.38 0.33 0.34 0.34
Strip Ratio (Bcy/Recovered
Ton)......................... 2.60 2.08 2.10 2.12 2.24
Effective Strip Ratio (Bcy/
Rec.Ton)..................... 2.60 2.08 2.10 2.12 2.28
One-Way Distance (Mi).......... 4.76 5.13 6.17 7.21 7.21
Coal Sales Tonnage:
Customer #1 -- CELP (Waste
Coal)...................... 125 250 250 250 250
Customer #2 -- Colstrip #3 &
#4......................... 3,485 6,971 6,971 6,971 6,971
------ ------ ------ ------ ------
Total Sales Tonnage........ 3,610 7,221 7,221 7,221 7,221
FOR CHASE SECURITIES, INC. 2004 2005 2006 2007 2008 2009
- -------------------------- ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)...... 19,203 21,923 24,569 26,283 29,041 31,649
Contract Pre-Bench Volume
(Bcy-000).................... -- -- 115 52 78 103
Dozer Pre-Bench Volume
(Bcy-000).................... 1,030 1,716 2,197 3,327 4,456 5,585
Dragline Strip Volume:
Virgin (Bcy-000)............. 18,173 20,207 22,257 22,905 24,508 25,961
Rehandle (Bcy-000)........... 1,104 1,820 2,339 3,683 4,753 5,972
------ ------ ------ ------ ------ ------
Total Dragline............. 19,277 22,027 24,596 26,588 29,260 31,932
Total Effective Overburden
(Bcy-000).................... 20,307 23,743 26,908 29,967 33,794 37,620
COAL PRODUCTION
Coal Recovered (Tons-000) Area
C............................ 6,971 6,971 6,971 6,971 6,971 6,971
Area F....................... -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total...................... 6,971 6,971 6,971 6,971 6,971 6,971
Product Coal Quality (As-Recd):
Ash (%)........................ 9.41 9.41 9.41 9.41 9.41 9.34
Sulfur (%)..................... 0.68 0.68 0.68 0.68 0.68 0.68
Btu/Lb......................... 8,509 8,509 8,509 8,509 8,509 8,509
Na(2)O in Ash (%).............. 0.34 0.34 0.34 0.34 0.34 0.48
Strip Ratio (Bcy/Recovered
Ton)......................... 2.75 3.14 3.52 3.77 4.17 4.54
Effective Strip Ratio (Bcy/
Rec.Ton)..................... 2.91 3.41 3.86 4.30 4.85 5.40
One-Way Distance (Mi).......... 7.21 7.21 7.21 5.06 5.06 5.06
Coal Sales Tonnage:
Customer #1 -- CELP (Waste
Coal)...................... 250 250 250 250 250 250
Customer #2 -- Colstrip #3 &
#4......................... 6,971 6,971 6,971 6,971 6,971 6,971
------ ------ ------ ------ ------ ------
Total Sales Tonnage........ 7,221 7,221 7,221 7,221 7,221 7,221
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)...... 34,351 36,921 39,037 39,037 39,037 39,037
Contract Pre-Bench Volume
(Bcy-000).................... 130 150 -- -- -- --
Dozer Pre-Bench Volume
(Bcy-000).................... 6,714 7,844 11,456 11,456 11,456 11,456
Dragline Strip Volume:
Virgin (Bcy-000)............. 27,507 28,927 27,582 27,582 27,582 27,582
Rehandle (Bcy-000)........... 7,097 8,427 9,077 9,077 9,077 9,077
------ ------ ------ ------ ------ ------
Total Dragline............. 34,604 37,354 36,659 36,659 36,659 36,659
Total Effective Overburden
(Bcy-000).................... 41,448 45,348 48,114 48,114 48,114 48,114
COAL PRODUCTION
Coal Recovered (Tons-000) Area
C............................ 6,971 6,971 6,971 6,971 6,971 6,971
Area F....................... -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total...................... 6,971 6,971 6,971 6,971 6,971 6,971
Product Coal Quality (As-Recd):
Ash (%)........................ 9.34 9.34 9.28 9.28 9.28 9.28
Sulfur (%)..................... 0.68 0.68 0.68 0.68 0.68 0.68
Btu/Lb......................... 8,509 8,509 8,509 8,509 8,509 8,509
Na(2)O in Ash (%).............. 0.48 0.48 0.48 0.60 0.60 0.60
Strip Ratio (Bcy/Recovered
Ton)......................... 4.93 5.30 5.60 5.60 5.60 5.60
Effective Strip Ratio (Bcy/
Rec.Ton)..................... 5.95 6.51 6.90 6.90 6.90 6.90
One-Way Distance (Mi).......... 5.06 5.06 4.53 4.53 4.53 4.53
Coal Sales Tonnage:
Customer #1 -- CELP (Waste
Coal)...................... 250 250 250 250 250 250
Customer #2 -- Colstrip #3 &
#4......................... 6,971 6,971 6,971 6,971 6,971 6,971
------ ------ ------ ------ ------ ------
Total Sales Tonnage........ 7,221 7,221 7,221 7,221 7,221 7,221
4-20
324
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003
- -------------------------- ------ ------ ------ ------ ------
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting............ 907 1,453 1,470 1,485 1,569
Contract Pre-Bench............. -- -- -- -- --
Dozer Pre-Bench................ -- -- -- -- 44
Dragline Stripping............. 1,633 2,615 2,646 2,673 2,834
Misc. Overburden Removal....... 91 145 147 148 157
------ ------ ------ ------ ------
Total Overburden Cost
($-000).................. 2,632 4,214 4,264 4,306 4,603
COAL MINING OPERATIONS:
Drilling & Blasting............ 244 488 488 488 488
Coal Cleaning.................. 139 279 279 279 279
Coal Loading/Pit Pumping....... 730 1,459 1,459 1,459 1,459
Coal Haulage & Roads........... 2,210 4,677 5,399 5,639 5,639
Stockpile and Crushing......... 592 1,185 1,185 1,185 1,185
------ ------ ------ ------ ------
Total Coal Mining Cost
($-000).................. 3,915 8,089 8,811 9,050 9,050
RECLAMATION OPERATIONS:
Ongoing Reclamation............ 976 1,952 1,952 1,952 1,952
Final Recl. Accrual............ 314 627 627 627 627
------ ------ ------ ------ ------
Reclamation Cost ($-000)... 1,289 2,579 2,579 2,579 2,579
OTHER EXPENDITURES:
Power Systems Maintenance...... 68 135 135 135 135
Supervisory/Engineering........ 975 1,950 1,950 1,950 1,950
Warehouse/Inventory............ 400 400 400 400 400
Unallocated Maintenance........ 592 1,185 1,185 1,185 1,185
Lease Rent & Records........... 67 67 67 67 67
A & G and Overheads............ 2,625 5,250 5,250 5,250 5,250
------ ------ ------ ------ ------
Total Other Cost ($-000)... 4,727 8,987 8,987 8,987 8,987
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All
Coal......................... 12,563 23,869 24,641 24,922 25,220
Total Dollars ($-000) Units 3&4
Fuel......................... 12,424 23,590 24,362 24,643 24,941
MINE COST BY FUNCTION ($/TON --
UNITS 3&4 FUEL ONLY)
Overburden Removal............. 0.76 0.60 0.61 0.62 0.66
Coal Mining.................... 1.08 1.12 1.22 1.26 1.26
Reclamation.................... 0.37 0.37 0.37 0.37 0.37
Other Expenses................. 1.36 1.29 1.29 1.29 1.29
------ ------ ------ ------ ------
Total...................... 3.56 3.38 3.49 3.54 3.58
FOR CHASE SECURITIES, INC. 2004 2005 2006 2007 2008 2009
- -------------------------- ------ ------ ------ ------ ------ ------
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting............ 1,930 2,205 2,474 2,649 2,930 3,197
Contract Pre-Bench............. -- -- 104 47 70 93
Dozer Pre-Bench................ 217 362 465 704 944 1,185
Dragline Stripping............. 3,487 3,989 4,458 4,824 5,314 5,805
Misc. Overburden Removal....... 193 221 247 265 293 320
------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000).................. 5,827 6,777 7,748 8,490 9,552 10,600
COAL MINING OPERATIONS:
Drilling & Blasting............ 488 488 488 488 488 488
Coal Cleaning.................. 279 279 279 279 279 279
Coal Loading/Pit Pumping....... 1,459 1,459 1,459 1,459 1,459 1,459
Coal Haulage & Roads........... 5,639 5,156 5,156 4,290 4,290 4,290
Stockpile and Crushing......... 1,185 1,185 1,185 1,185 1,185 1,185
------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000).................. 9,050 8,568 8,568 7,701 7,701 7,701
RECLAMATION OPERATIONS:
Ongoing Reclamation............ 1,952 1,952 1,952 1,952 1,952 1,952
Final Recl. Accrual............ 627 627 627 627 627 627
------ ------ ------ ------ ------ ------
Reclamation Cost ($-000)... 2,579 2,579 2,579 2,579 2,579 2,579
OTHER EXPENDITURES:
Power Systems Maintenance...... 135 135 135 135 135 135
Supervisory/Engineering........ 1,950 1,950 1,950 1,950 1,950 1,950
Warehouse/Inventory............ 400 400 400 400 400 400
Unallocated Maintenance........ 1,185 1,185 1,185 1,185 1,185 1,185
Lease Rent & Records........... 67 67 67 67 67 67
A & G and Overheads............ 5,250 5,250 5,250 5,250 5,250 5,250
------ ------ ------ ------ ------ ------
Total Other Cost ($-000)... 8,987 8,987 8,987 8,987 8,987 8,987
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All
Coal......................... 26,444 26,911 27,882 27,757 28,820 29,867
Total Dollars ($-000) Units 3&4
Fuel......................... 26,165 26,632 27,604 27,478 28,541 29,588
MINE COST BY FUNCTION ($/TON --
UNITS 3&4 FUEL ONLY)
Overburden Removal............. 0.84 0.97 1.11 1.22 1.37 1.52
Coal Mining.................... 1.26 1.19 1.19 1.06 1.06 1.06
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses................. 1.29 1.29 1.29 1.29 1.29 1.29
------ ------ ------ ------ ------ ------
Total...................... 3.75 3.82 3.96 3.94 4.09 4.24
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting............ 3,473 3,736 3,954 3,958 3,962 3,966
Contract Pre-Bench............. 119 137 -- -- -- --
Dozer Pre-Bench................ 1,426 1,667 2,437 2,439 2,442 2,444
Dragline Stripping............. 6,297 6,804 6,684 6,691 6,698 6,704
Misc. Overburden Removal....... 347 374 395 396 396 397
------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000).................. 11,661 12,718 13,471 13,485 13,498 13,511
COAL MINING OPERATIONS:
Drilling & Blasting............ 488 488 488 488 488 488
Coal Cleaning.................. 279 279 279 279 279 279
Coal Loading/Pit Pumping....... 1,459 1,459 1,459 1,459 1,459 1,459
Coal Haulage & Roads........... 4,290 4,290 3,957 3,957 3,957 3,957
Stockpile and Crushing......... 1,185 1,185 1,185 1,185 1,185 1,185
------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000).................. 7,701 7,701 7,369 7,369 7,369 7,369
RECLAMATION OPERATIONS:
Ongoing Reclamation............ 1,952 1,952 1,952 1,952 1,952 1,952
Final Recl. Accrual............ 627 627 627 627 627 627
------ ------ ------ ------ ------ ------
Reclamation Cost ($-000)... 2,579 2,579 2,579 2,579 2,579 2,579
OTHER EXPENDITURES:
Power Systems Maintenance...... 135 135 135 135 135 135
Supervisory/Engineering........ 1,950 1,950 1,950 1,950 1,950 1,950
Warehouse/Inventory............ 400 400 400 400 400 400
Unallocated Maintenance........ 1,185 1,185 1,185 1,185 1,185 1,185
Lease Rent & Records........... 67 67 67 67 67 67
A & G and Overheads............ 5,250 5,250 5,250 5,250 5,250 5,250
------ ------ ------ ------ ------ ------
Total Other Cost ($-000)... 8,987 8,987 8,987 8,987 8,987 8,987
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All
Coal......................... 30,929 31,986 32,406 32,420 32,433 32,446
Total Dollars ($-000) Units 3&4
Fuel......................... 30,650 31,707 32,128 32,141 32,154 32,167
MINE COST BY FUNCTION ($/TON --
UNITS 3&4 FUEL ONLY)
Overburden Removal............. 1.67 1.82 1.93 1.93 1.94 1.94
Coal Mining.................... 1.06 1.06 1.02 1.02 1.02 1.02
Reclamation.................... 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses................. 1.29 1.29 1.29 1.29 1.29 1.29
------ ------ ------ ------ ------ ------
Total...................... 4.40 4.55 4.61 4.61 4.61 4.61
4-21
325
FOR CHASE SECURITIES, INC. 1999 2000 2001 2002 2003
- -------------------------- ------ ------ ------ ------ ------
MINE COST BY CONTRACT CATEGORY
($/TON -- UNITS 3&4 FUEL ONLY)
Labor.......................... 0.99 0.92 0.96 0.97 0.98
Power.......................... 0.28 0.25 0.25 0.25 0.26
Materials & Supplies........... 1.15 1.09 1.16 1.19 1.21
Reclamation (Excl Accrual)..... 0.28 0.28 0.28 0.28 0.28
A & G and Overheads............ 0.77 0.76 0.76 0.76 0.76
------ ------ ------ ------ ------
Total ($/Ton).............. 3.47 3.29 3.40 3.45 3.49
TOTAL CAPITAL EXPENDITURE
($-000):
Site Preparation............... 366 974 520 932 920
Buildings & Infrastructure..... -- 2,495 710 410 985
Mining Equipment............... 2,210 10,650 4,740 1,850 3,950
Support Equipment.............. 385 436 210 170 170
------ ------ ------ ------ ------
Total Capital.............. 2,961 14,555 6,180 3,362 6,025
Depreciation $/Yr (000)........ 2,327 3,062 3,997 4,302 4,555
$/Ton (Units 3&4 Fuel
Only).................... 0.67 0.44 0.57 0.62 0.65
FOR CHASE SECURITIES, INC. 2004 2005 2006 2007 2008 2009
- -------------------------- ------ ------ ------ ------ ------ ------
MINE COST BY CONTRACT CATEGORY
($/TON -- UNITS 3&4 FUEL ONLY)
Labor.......................... 1.03 1.04 1.08 1.07 1.11 1.15
Power.......................... 0.29 0.31 0.33 0.35 0.37 0.40
Materials & Supplies........... 1.30 1.33 1.41 1.39 1.48 1.57
Reclamation (Excl Accrual)..... 0.28 0.28 0.28 0.28 0.28 0.28
A & G and Overheads............ 0.76 0.76 0.76 0.76 0.76 0.76
------ ------ ------ ------ ------ ------
Total ($/Ton).............. 3.66 3.73 3.87 3.85 4.00 4.15
TOTAL CAPITAL EXPENDITURE
($-000):
Site Preparation............... -- -- -- -- -- --
Buildings & Infrastructure..... 132 132 132 132 132 132
Mining Equipment............... 4,465 5,665 1,665 2,015 1,665 2,100
Support Equipment.............. 660 855 585 585 660 585
------ ------ ------ ------ ------ ------
Total Capital.............. 5,257 6,652 2,382 2,732 2,457 2,817
Depreciation $/Yr (000)........ 5,057 5,519 5,846 5,980 5,996 5,948
$/Ton (Units 3&4 Fuel
Only).................... 0.73 0.79 0.84 0.86 0.86 0.85
FOR CHASE SECURITIES, INC. 2010 2011 2012 2013 2014 2015
- -------------------------- ------ ------ ------ ------ ------ ------
MINE COST BY CONTRACT CATEGORY
($/TON -- UNITS 3&4 FUEL ONLY)
Labor.......................... 1.19 1.23 1.24 1.24 1.24 1.24
Power.......................... 0.42 0.44 0.45 0.45 0.45 0.45
Materials & Supplies........... 1.65 1.74 1.79 1.79 1.79 1.79
Reclamation (Excl Accrual)..... 0.28 0.28 0.28 0.28 0.28 0.28
A & G and Overheads............ 0.76 0.76 0.76 0.76 0.76 0.76
------ ------ ------ ------ ------ ------
Total ($/Ton).............. 4.31 4.46 4.52 4.52 4.52 4.52
TOTAL CAPITAL EXPENDITURE
($-000):
Site Preparation............... -- -- -- -- -- --
Buildings & Infrastructure..... 132 132 132 132 132 132
Mining Equipment............... 5,165 4,865 4,915 1,365 5,865 3,565
Support Equipment.............. 855 585 885 585 660 855
------ ------ ------ ------ ------ ------
Total Capital.............. 6,152 5,582 5,932 2,082 6,657 4,552
Depreciation $/Yr (000)........ 6,117 6,217 6,062 5,759 5,760 5,620
$/Ton (Units 3&4 Fuel
Only).................... 0.88 0.89 0.87 0.83 0.83 0.81
- ---------------
Note: Projections based on data from January 1999
4-22
326
TABLE 4.3 -- CONTINUED
MINE PLAN AND COST ESTIMATE
ROSEBUD MINE -- UNITS 3 & 4 FUEL SUPPLY (AREAS C & F)
FOR CHASE SECURITIES INC 2016 2017 2018 2019 2020
- ------------------------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)........ 39,139 38,859 38,859 42,422 22,845
Contract Pre-Bench Volume
(Bcy-000)........................ 101 800 800 840 --
Dozer Pre-Bench Volume (Bcy-000)... 11,456 13,719 13,719 14,483 1,088
Dragline Strip Volume:
Virgin (Bcy-000)................. 27,582 24,339 24,339 27,099 21,757
Rehandle (Bcy-000)............... 9,077 8,963 8,963 9,484 1,034
------ ------ ------ ------ ------
Total Dragline................. 36,659 33,302 33,302 36,583 22,790
Total Effective Overburden
(Bcy-000)........................ 48,216 47,821 47,821 51,906 23,879
COAL PRODUCTION
Coal Recovered (Tons-000)
Area C........................... 6,971 6,971 6,971 6,971 --
Area F........................... -- -- -- -- 6,900
------ ------ ------ ------ ------
Total.......................... 6,971 6,971 6,971 6,971 6,900
Product Coal Quality (As-Recd):
Ash (%).......................... 9.28 9.22 9.22 9.17 8.68
Sulfur (%)....................... 0.68 0.68 0.68 0.69 0.77
Btu/Lb........................... 8,509 8,508 8,508 8,516 8,591
Na2O in Ash (%).................. 0.60 0.62 0.62 0.66 1.05
Strip Ratio (Bcy/Recovered Ton):... 5.61 5.57 5.57 6.09 3.31
Effective Strip Ratio
(Bcy/Rec.Ton):................... 6.92 6.86 6.86 7.45 3.46
One-Way Distance (Mi).............. 4.53 5.65 5.65 5.65 6.20
Coal Sales Tonnage:
Customer #1 -- CELP (Waste Coal)... 250 250 250 250 250
Customer #2 -- Colstrip #3 & #4.... 6,971 6,971 6,971 6,971 6,900
------ ------ ------ ------ ------
Total Sales Tonnage............ 7,221 7,221 7,221 7,221 7,150
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting................ 3,980 3,956 3,960 4,242 2,287
Contract Pre-Bench................. 93 733 734 756 --
Dozer Pre-Bench.................... 2,447 2,933 2,936 3,041 229
Dragline Stripping................. 6,711 6,102 6,108 6,585 4,106
Misc. Overburden Removal........... 398 396 396 424 229
------ ------ ------ ------ ------
Total Overburden Cost
($-000)...................... 13,629 14,120 14,133 15,049 6,851
COAL MINING OPERATIONS:
Drilling & Blasting................ 488 488 488 488 483
Coal Cleaning...................... 279 279 279 279 276
Coal Loading/Pit Pumping........... 1,459 1,459 1,459 1,459 1,446
Coal Haulage & Roads............... 3,957 4,660 4,660 4,660 4,954
Stockpile and Crushing............. 1,185 1,185 1,185 1,185 1,173
------ ------ ------ ------ ------
Total Coal Mining Cost
($-000)...................... 7,369 8,071 8,071 8,071 8,332
RECLAMATION OPERATIONS:
Ongoing Reclamation................ 1,952 1,952 1,952 1,952 1,932
FOR CHASE SECURITIES INC 2021 2022 2023 2024 2025 2026
- ------------------------ ------ ------ ------ ------ ------ ------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)........ 22,659 20,257 28,203 33,101 34,066 41,283
Contract Pre-Bench Volume
(Bcy-000)........................ -- -- 25 50 47 676
Dozer Pre-Bench Volume (Bcy-000)... 1,043 658 4,269 5,401 5,934 11,351
Dragline Strip Volume:
Virgin (Bcy-000)................. 21,616 19,599 23,910 27,650 28,086 29,255
Rehandle (Bcy-000)............... 990 587 3,484 4,332 4,813 7,888
------ ------ ------ ------ ------ ------
Total Dragline................. 22,607 20,186 27,394 31,982 32,900 37,143
Total Effective Overburden
(Bcy-000)........................ 23,649 20,844 31,687 37,433 38,880 49,170
COAL PRODUCTION
Coal Recovered (Tons-000)
Area C........................... -- -- -- -- -- --
Area F........................... 6,900 6,900 6,900 6,900 6,900 6,900
------ ------ ------ ------ ------ ------
Total.......................... 6,900 6,900 6,900 6,900 6,900 6,900
Product Coal Quality (As-Recd):
Ash (%).......................... 8.68 8.68 8.68 8.68 8.68 8.68
Sulfur (%)....................... 0.77 0.77 0.77 0.77 0.77 0.77
Btu/Lb........................... 8,591 8,591 8,591 8,591 8,591 8,591
Na2O in Ash (%).................. 1.05 1.05 1.05 1.05 1.05 1.05
Strip Ratio (Bcy/Recovered Ton):... 3.28 2.94 4.09 4.80 4.94 5.98
Effective Strip Ratio
(Bcy/Rec.Ton):................... 3.43 3.02 4.59 5.43 5.63 7.13
One-Way Distance (Mi).............. 10.90 11.10 13.80 14.60 13.40 12.70
Coal Sales Tonnage:
Customer #1 -- CELP (Waste Coal)... 250 250 250 250 250 250
Customer #2 -- Colstrip #3 & #4.... 6,900 6,900 6,900 6,900 6,900 6,900
------ ------ ------ ------ ------ ------
Total Sales Tonnage............ 7,150 7,150 7,150 7,150 7,150 7,150
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting................ 2,270 2,032 2,832 3,327 3,427 4,157
Contract Pre-Bench................. -- -- 22 45 42 613
Dozer Pre-Bench.................... 219 139 900 1,140 1,254 2,400
Dragline Stripping................. 4,077 3,644 4,951 5,785 5,957 6,733
Misc. Overburden Removal........... 227 203 283 333 343 416
------ ------ ------ ------ ------ ------
Total Overburden Cost
($-000)...................... 6,794 6,018 8,988 10,630 11,023 14,319
COAL MINING OPERATIONS:
Drilling & Blasting................ 483 483 483 483 483 483
Coal Cleaning...................... 276 276 276 276 276 276
Coal Loading/Pit Pumping........... 1,446 1,446 1,446 1,446 1,446 1,446
Coal Haulage & Roads............... 7,151 7,262 8,760 9,203 8,538 8,149
Stockpile and Crushing............. 1,173 1,173 1,173 1,173 1,173 1,173
------ ------ ------ ------ ------ ------
Total Coal Mining Cost
($-000)...................... 10,529 10,640 12,138 12,581 11,916 11,527
RECLAMATION OPERATIONS:
Ongoing Reclamation................ 1,932 1,932 1,932 1,932 1,932 1,932
FOR CHASE SECURITIES INC 2027 2028 2029 2030 TOTAL
- ------------------------ ------ ------ ------ ------ ---------
OVERBURDEN REMOVAL
Virgin Overburden (Bcy-000)........ 45,142 45,142 45,920 51,076 997,756
Contract Pre-Bench Volume
(Bcy-000)........................ 1,218 1,218 1,039 2,319 9,758
Dozer Pre-Bench Volume (Bcy-000)... 14,706 14,706 15,247 18,845 225,523
Dragline Strip Volume:
Virgin (Bcy-000)................. 29,218 29,218 29,635 29,912 762,474
Rehandle (Bcy-000)............... 9,369 9,369 10,021 11,724 171,858
------ ------ ------ ------ ---------
Total Dragline................. 38,587 38,587 39,656 41,636 934,332
Total Effective Overburden
(Bcy-000)........................ 54,511 54,511 55,941 62,801 1,169,614
COAL PRODUCTION
Coal Recovered (Tons-000)
Area C........................... -- -- -- -- 142,905
Area F........................... 6,900 6,900 6,900 6,900 75,900
------ ------ ------ ------ ---------
Total.......................... 6,900 6,900 6,900 6,900 218,805
Product Coal Quality (As-Recd):
Ash (%).......................... 8.68 8.68 8.68 8.68
Sulfur (%)....................... 0.77 0.77 0.77 0.77
Btu/Lb........................... 8,591 8,591 8,591 8,591
Na2O in Ash (%).................. 1.05 1.05 1.05 1.05
Strip Ratio (Bcy/Recovered Ton):... 6.54 6.54 6.66 7.40 4.56
Effective Strip Ratio
(Bcy/Rec.Ton):................... 7.90 7.90 8.11 9.10 5.35
One-Way Distance (Mi).............. 12.10 12.10 11.00 14.90
Coal Sales Tonnage:
Customer #1 -- CELP (Waste Coal)... 250 250 250 250 7,875
Customer #2 -- Colstrip #3 & #4.... 6,900 6,900 6,900 6,900 218,805
------ ------ ------ ------ ---------
Total Sales Tonnage............ 7,150 7,150 7,150 7,150 226,680
MINE OPERATING COSTS ($-000):
OVERBURDEN REMOVAL OPERATIONS:
Drilling & Blasting................ 4,550 4,555 4,638 5,164 100,697
Contract Pre-Bench................. 1,105 1,106 944 2,110 8,872
Dozer Pre-Bench.................... 3,113 3,116 3,234 4,001 47,877
Dragline Stripping................. 7,001 7,008 7,209 7,577 169,714
Misc. Overburden Removal........... 455 455 464 516 10,070
------ ------ ------ ------ ---------
Total Overburden Cost
($-000)...................... 16,224 16,240 16,489 19,368 337,230
COAL MINING OPERATIONS:
Drilling & Blasting................ 483 483 483 483 15,316
Coal Cleaning...................... 276 276 276 276 8,752
Coal Loading/Pit Pumping........... 1,446 1,446 1,446 1,446 45,825
Coal Haulage & Roads............... 7,817 7,817 7,206 9,370 180,960
Stockpile and Crushing............. 1,173 1,173 1,173 1,173 37,197
------ ------ ------ ------ ---------
Total Coal Mining Cost
($-000)...................... 11,195 11,195 10,584 12,748 288,050
RECLAMATION OPERATIONS:
Ongoing Reclamation................ 1,932 1,932 1,932 1,932 61,265
4-23
327
FOR CHASE SECURITIES INC 2016 2017 2018 2019 2020
- ------------------------ ------ ------ ------ ------ ------
Final Recl. Accrual................ 627 627 627 627 621
------ ------ ------ ------ ------
Reclamation Cost ($-000)....... 2,579 2,579 2,579 2,579 2,553
OTHER EXPENDITURES:
Power Systems Maintenance.......... 135 135 135 135 135
Supervisory/Engineering............ 1,950 1,950 1,950 1,950 1,950
Warehouse/Inventory................ 400 400 400 400 400
Unallocated Maintenance............ 1,185 1,185 1,185 1,185 1,173
Lease Rent & Records............... 67 67 67 67 67
A & G and Overheads................ 5,250 5,250 5,250 5,250 5,250
------ ------ ------ ------ ------
Total Other Cost ($-000)....... 8,987 8,987 8,987 8,987 8,975
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All Coal..... 32,564 33,757 33,771 34,687 26,711
Total Dollars ($-000) Units 3&4
Fuel............................. 32,285 33,479 33,492 34,408 26,435
MINE COST BY FUNCTION ($/TON -- UNITS
3&4 FUEL ONLY)
Overburden Removal................. 1.96 2.03 2.03 2.16 0.99
Coal Mining........................ 1.02 1.12 1.12 1.12 1.17
Reclamation........................ 0.37 0.37 0.37 0.37 0.37
Other Expenses..................... 1.29 1.29 1.29 1.29 1.30
------ ------ ------ ------ ------
Total.......................... 4.63 4.80 4.80 4.94 3.83
MINE COST BY CONTRACT CATEGORY ($/
TON -- UNITS 3&4 FUEL ONLY)
Labor.............................. 1.25 1.30 1.30 1.33 1.04
Power.............................. 0.45 0.42 0.42 0.45 0.32
Materials & Supplies............... 1.80 1.95 1.95 2.02 1.33
Reclamation (Excl Accrual)......... 0.28 0.28 0.28 0.28 0.28
A & G and Overheads................ 0.76 0.76 0.76 0.76 0.77
------ ------ ------ ------ ------
Total ($/Ton).................. 4.54 4.71 4.71 4.85 3.74
TOTAL CAPITAL EXPENDITURE ($-000):
Site Preparation................... -- -- -- 1,050 500
Buildings & Infrastructure......... 132 132 132 982 2,782
Mining Equipment................... 2,715 1,865 1,365 9,900 4,365
Support Equipment.................. 585 585 660 585 855
------ ------ ------ ------ ------
Total Capital.................. 3,432 2,582 2,157 12,517 8,502
Depreciation $/Yr (000)............ 5,305 5,149 4,970 5,056 4,769
$/Ton (Units 3&4 Fuel Only).... 0.76 0.74 0.71 0.73 0.69
FOR CHASE SECURITIES INC 2021 2022 2023 2024 2025 2026
- ------------------------ ------ ------ ------ ------ ------ ------
Final Recl. Accrual................ 621 621 621 621 621 621
------ ------ ------ ------ ------ ------
Reclamation Cost ($-000)....... 2,553 2,553 2,553 2,553 2,553 2,553
OTHER EXPENDITURES:
Power Systems Maintenance.......... 135 135 135 135 135 135
Supervisory/Engineering............ 1,950 1,950 1,950 1,950 1,950 1,950
Warehouse/Inventory................ 400 400 400 400 400 400
Unallocated Maintenance............ 1,173 1,173 1,173 1,173 1,173 1,173
Lease Rent & Records............... 67 67 67 67 67 67
A & G and Overheads................ 5,250 5,250 5,250 5,250 5,250 5,250
------ ------ ------ ------ ------ ------
Total Other Cost ($-000)....... 8,975 8,975 8,975 8,975 8,975 8,975
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All Coal..... 28,851 28,186 32,653 34,739 34,467 37,374
Total Dollars ($-000) Units 3&4
Fuel............................. 28,575 27,910 32,377 34,463 34,191 37,098
MINE COST BY FUNCTION ($/TON -- UNITS
3&4 FUEL ONLY)
Overburden Removal................. 0.98 0.87 1.30 1.54 1.60 2.08
Coal Mining........................ 1.49 1.50 1.72 1.78 1.69 1.63
Reclamation........................ 0.37 0.37 0.37 0.37 0.37 0.37
Other Expenses..................... 1.30 1.30 1.30 1.30 1.30 1.30
------ ------ ------ ------ ------ ------
Total.......................... 4.14 4.04 4.69 4.99 4.96 5.38
MINE COST BY CONTRACT CATEGORY ($/
TON -- UNITS 3&4 FUEL ONLY)
Labor.............................. 1.15 1.13 1.32 1.41 1.39 1.50
Power.............................. 0.32 0.30 0.36 0.40 0.41 0.45
Materials & Supplies............... 1.53 1.48 1.87 2.04 2.01 2.28
Reclamation (Excl Accrual)......... 0.28 0.28 0.28 0.28 0.28 0.28
A & G and Overheads................ 0.77 0.77 0.77 0.77 0.77 0.77
------ ------ ------ ------ ------ ------
Total ($/Ton).................. 4.05 3.95 4.60 4.90 4.87 5.29
TOTAL CAPITAL EXPENDITURE ($-000):
Site Preparation................... -- -- -- -- -- --
Buildings & Infrastructure......... 132 132 132 132 132 132
Mining Equipment................... 10,915 4,365 1,565 3,565 2,765 1,915
Support Equipment.................. 585 885 585 660 855 585
------ ------ ------ ------ ------ ------
Total Capital.................. 11,632 5,382 2,282 4,357 3,752 2,632
Depreciation $/Yr (000)............ 4,737 5,226 5,266 5,249 5,332 5,316
$/Ton (Units 3&4 Fuel Only).... 0.69 0.76 0.76 0.76 0.77 0.77
FOR CHASE SECURITIES INC 2027 2028 2029 2030 TOTAL
- ------------------------ ------ ------ ------ ------ ---------
Final Recl. Accrual................ 621 621 621 621 19,692
------ ------ ------ ------ ---------
Reclamation Cost ($-000)....... 2,553 2,553 2,553 2,553 80,958
OTHER EXPENDITURES:
Power Systems Maintenance.......... 135 135 135 135 4,253
Supervisory/Engineering............ 1,950 1,950 1,950 1,950 61,425
Warehouse/Inventory................ 400 400 400 400 12,800
Unallocated Maintenance............ 1,173 1,173 1,173 1,173 37,197
Lease Rent & Records............... 67 67 67 67 2,144
A & G and Overheads................ 5,250 5,250 5,250 5,250 165,375
------ ------ ------ ------ ---------
Total Other Cost ($-000)....... 8,975 8,975 8,975 8,975 283,193
TOTAL MINE OPERATING EXPENSE:
Total Dollars ($-000) All Coal..... 38,947 38,963 38,601 43,644 989,432
Total Dollars ($-000) Units 3&4
Fuel............................. 38,671 38,687 38,325 43,368 980,680
MINE COST BY FUNCTION ($/TON -- UNITS
3&4 FUEL ONLY)
Overburden Removal................. 2.35 2.35 2.39 2.81 1.54
Coal Mining........................ 1.58 1.58 1.49 1.81 1.28
Reclamation........................ 0.37 0.37 0.37 0.37 0.37
Other Expenses..................... 1.30 1.30 1.30 1.30 1.29
------ ------ ------ ------ ---------
Total.......................... 5.60 5.61 5.55 6.29 4.48
MINE COST BY CONTRACT CATEGORY ($/
TON -- UNITS 3&4 FUEL ONLY)
Labor.............................. 1.55 1.55 1.53 1.75 1.23
Power.............................. 0.47 0.47 0.48 0.51 0.38
Materials & Supplies............... 2.44 2.44 2.40 2.89 1.70
Reclamation (Excl Accrual)......... 0.28 0.28 0.28 0.28 0.28
A & G and Overheads................ 0.77 0.77 0.77 0.77 0.77
------ ------ ------ ------ ---------
Total ($/Ton).................. 5.51 5.52 5.46 6.20 4.36
TOTAL CAPITAL EXPENDITURE ($-000):
Site Preparation................... -- -- -- -- 5,262
Buildings & Infrastructure......... 50 -- -- -- 11,186
Mining Equipment................... 1,200 700 50 -- 113,965
Support Equipment.................. 370 260 155 -- 17,936
------ ------ ------ ------ ---------
Total Capital.................. 1,620 960 205 -- 148,349
Depreciation $/Yr (000)............ 5,176 4,948 4,348 3,649 162,619
$/Ton (Units 3&4 Fuel Only).... 0.75 0.72 0.63 0.53 0.74
- ---------------
Note: Projections based on data from January 1999
4-24
328
TABLE 4.4
CONVEYOR OPERATING COST ESTIMATE
ROSEBUD MINE -- UNITS 3 & 4 (AREAS C & F)
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
YEAR: 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
COAL CONVEYED (TONS-000).......... 3,485 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971
CONVEYOR OPERATING COSTS
Operating Expense by Category
($-000)
Labor......................... 345 690 690 690 690 690 690 690 690 690 690 690
Power......................... 230 460 460 460 460 460 460 460 460 460 460 460
Materials & Supplies.......... 192 383 383 383 383 383 383 383 383 383 383 383
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total ($/Ton Sold).......... 767 1,534 1,534 1,534 1,534 1,534 1,534 1,534 1,534 1,534 1,534 1,534
Operating Expense by Category
($/Ton)
Labor......................... 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10
Power......................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07
Materials & Supplies.......... 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Dollars ($-000)....... 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22
CONVEYOR CAPITAL COSTS ($-000):
Facility Upgrades............. -- -- -- -- 100 -- -- -- -- 100 -- --
Conveyor Belting &
Structure................... 160 160 160 160 160 160 160 160 160 160 160 160
Maintenance/Support
Equipment................... 30 60 30 60 30 60 30 60 30 60 30 60
Miscellaneous................. 25 25 25 25 25 25 25 25 25 25 25 25
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Capital ($-000)....... 215 245 215 245 315 245 215 245 215 345 215 245
Conveyor Depreciation
($-000)..................... 473 506 533 557 592 621 642 685 698 693 687 680
Conveyor Depreciation
($/Ton)..................... 0.14 0.07 0.08 0.08 0.08 0.09 0.09 0.10 0.10 0.10 0.10 0.10
YEAR: 2011 2012 2013 2014 2015
- ----- ----- ----- ----- ----- -----
COAL CONVEYED (TONS-000).......... 6,971 6,971 6,971 6,971 6,971
CONVEYOR OPERATING COSTS
Operating Expense by Category
($-000)
Labor......................... 690 690 690 690 690
Power......................... 460 460 460 460 460
Materials & Supplies.......... 383 383 383 383 383
----- ----- ----- ----- -----
Total ($/Ton Sold).......... 1,534 1,534 1,534 1,534 1,534
Operating Expense by Category
($/Ton)
Labor......................... 0.10 0.10 0.10 0.10 0.10
Power......................... 0.07 0.07 0.07 0.07 0.07
Materials & Supplies.......... 0.06 0.06 0.06 0.06 0.06
----- ----- ----- ----- -----
Total Dollars ($-000)....... 0.22 0.22 0.22 0.22 0.22
CONVEYOR CAPITAL COSTS ($-000):
Facility Upgrades............. -- -- 100 -- --
Conveyor Belting &
Structure................... 160 160 160 160 160
Maintenance/Support
Equipment................... 30 60 30 60 30
Miscellaneous................. 25 25 25 25 25
----- ----- ----- ----- -----
Total Capital ($-000)....... 215 245 315 245 215
Conveyor Depreciation
($-000)..................... 626 626 629 633 633
Conveyor Depreciation
($/Ton)..................... 0.09 0.09 0.09 0.09 0.09
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YEAR: 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
COAL CONVEYED (TONS-000).......... 6,971 6,971 6,971 6,971 6,900 6,900 6,900 6,900 6,900 6,900 6,900 6,900
CONVEYOR OPERATING COSTS
Operating Expense by Category
($-000)
Labor......................... 690 690 690 690 683 683 683 683 683 683 683 683
Power......................... 460 460 460 460 455 455 455 455 455 455 455 455
Materials & Supplies.......... 383 383 383 383 380 380 380 380 380 380 380 380
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total ($/Ton Sold).......... 1,534 1,534 1,534 1,534 1,518 1,518 1,518 1,518 1,518 1,518 1,518 1,518
Operating Expense by Category
($/Ton)
Labor......................... 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10
Power......................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07
Materials & Supplies.......... 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Dollars ($-000)....... 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22
CONVEYOR CAPITAL COSTS ($-000):
Facility Upgrades............. -- -- 100 -- -- -- -- 100 -- -- -- --
Conveyor Belting &
Structure................... 160 160 160 160 160 160 160 160 160 160 100 50
Maintenance/Support
Equipment................... 60 30 60 30 60 30 60 30 60 30 60 20
Miscellaneous................. 25 25 25 25 25 25 25 25 25 25 25 20
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Capital ($-000)....... 245 215 345 215 245 215 245 315 245 215 185 90
Conveyor Depreciation
($-000)..................... 633 633 627 255 251 251 251 251 251 251 246 234
Conveyor Depreciation
($/Ton)..................... 0.09 0.09 0.09 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.03
1999-2030
YEAR: 2028 2029 2030 TOTAL
- ----- ----- ----- ----- ---------
COAL CONVEYED (TONS-000).......... 6,900 6,900 6,900 218,805
CONVEYOR OPERATING COSTS
Operating Expense by Category
($-000)
Labor......................... 683 683 683 21,662
Power......................... 455 455 455 14,441
Materials & Supplies.......... 380 380 380 12,034
----- ----- ----- -------
Total ($/Ton Sold).......... 1,518 1,518 1,518 48,137
Operating Expense by Category
($/Ton)
Labor......................... 0.10 0.10 0.10 0.10
Power......................... 0.07 0.07 0.07 0.07
Materials & Supplies.......... 0.06 0.06 0.06 0.06
----- ----- ----- -------
Total Dollars ($-000)....... 0.22 0.22 0.22 0.22
CONVEYOR CAPITAL COSTS ($-000):
Facility Upgrades............. -- -- -- 500
Conveyor Belting &
Structure................... -- -- -- 4,470
Maintenance/Support
Equipment................... -- -- -- 1,280
Miscellaneous................. 15 5 -- 740
----- ----- ----- -------
Total Capital ($-000)....... 15 5 -- 6,990
Conveyor Depreciation
($-000)..................... 206 172 140 15,168
Conveyor Depreciation
($/Ton)..................... 0.03 0.02 0.02 0.07
- ---------------
Note: Projections based on data from January 1999
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ALTERNATIVE SUPPLIES
5.1 INTRODUCTION
This study assumes that Colstrip will continue to acquire fuel from the
Rosebud Mine over the 30-year study period. However, should Rosebud costs prove
excessive or reserves inadequate, and for the period beyond 2030, alternative
fuel supplies are available. The most likely of these alternatives is the
Southern Powder River Basin (SPRB) of Wyoming, the current source of coal to
Corette.
This chapter addresses the SPRB mines, both as primary suppliers to
Corette, and as an alternative and/or post 2030 supply at Colstrip.
5.2 SOUTHERN POWDER RIVER BASIN
The SPRB includes portions of Campbell and Converse Counties, Wyoming (see
Figure 3.2). The area of active mining encompasses a three to six mile wide
north-south zone extending from approximately 15 miles north of Gillette,
Wyoming, to a point 60 miles south of Gillette. Within this area, the thick
Anderson-Wyodak coal seam is recoverable using low-cost surface mining methods.
Fifteen large mining operations are active in the area, producing about 270
million tons in 1998.
5.2.1 SPRB Geology and Reserves
The Anderson-Wyodak seam occurs in the Paleocene Fort Union Formation,
outcropping along a north-south trend and dipping to the west. The seam varies
from over 100 ft thick north of Gillette, to 50 - 70 ft thick at the southern
end of the deposit.
The SPRB constitutes the largest in-place coal resource in the contiguous
U.S. Regional reserve estimates are available from a variety of sources and vary
widely. The majority of the available tonnage is low sulfur compliance quality,
and at moderate depths. Even with relatively aggressive production projections,
the resources available in the SPRB are unlikely to be depleted prior to 2050.
SPRB coals are subbituminous in rank, and characterized by high moisture,
low sulfur, low ash, and relatively low heat content. Quality improves to the
south, with the highest Btu coals found in the southern portion of the deposit.
Following are typical quality ranges for SPRB coals:
PROXIMATE ANALYSIS
(AS-RECEIVED) SPRB
------------------ -------------
Moisture (%)................................................ 26.0 - 32.0
Ash (%)..................................................... 4.0 - 10.0
Volatile Matter (%)......................................... 29.0 - 33.0
Sulfur (%).................................................. 0.1 - 0.6
Lbs SO(2)/MM Btu............................................ 0.3 - 1.4
Btu/lb...................................................... 7,600 - 8,850
The north-south quality variations result in two distinct coal products.
The northern mines produce a lower Btu coal in the 8,300 - 8,500 Btu/lb range,
while the southern mines produce an 8,700 - 8,800 Btu/lb product. Sulfur content
is also lower at many of the southern mines, resulting in a "super compliance"
coal with less than 0.5 lbs SO(2)/MMBtu. Economics generally favor shipping the
higher Btu southern coal to more distant customers, while the lower Btu coals go
to plants closer to the mines.
All SPRB coal is sold raw after crushing and screening. There are several
projects planned or in place to upgrade SPRB coals, including production of
synfuels; however, these represent fairly small tonnages. In excess of 95% of
SPRB coal is sold for electric power generation.
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5.2.2 SPRB Supply
SPRB mines are typically large, high volume surface mining operations.
Average production is over 16 million tons per year, and the largest, Black
Thunder, produces in excess of 35 million tons annually. In 1997, there were 6
mines producing more than 20 MTPY (excludes Caballo at 19.9 million). The mines
typically employ the largest available equipment, high volume coal handling and
processing systems, and many other techniques to allow maximum advantage of the
operation's inherent economies of scale.
Production and quality data for the 15 active mines are summarized:
TYPICAL QUALITIES (AS-RECEIVED)
-------------------------------
1997 TONS ASH SULFUR
MINE (MILLIONS) (%) (%) BTU/LB
- ---- ---------- ----- -------- --------
Buckskin................................ 14.4 5.2 .40 8,450
Rawhide................................. 10.7 4.9 .40 8,320
Eagle Butte............................. 17.9 4.6 .41 8,350
Dry Fork................................ 0.9 4.8 .37 8,175
Fort Union.............................. 0.6 6.0 .40 8,200
Wyodak.................................. 3.3 6.0 .42 8,050
Caballo................................. 20.0 5.1 .38 8,400
Belle Ayr............................... 22.8 4.6 .30 8,550
Cordero Rojo............................ 28.0 5.6 .35 8,350
Coal Creek.............................. 2.9 5.7 .33 8,350
Jacobs Ranch............................ 27.1 5.6 .44 8,690
Black Thunder........................... 37.7 5.0 .28 8,850
North Rochelle.......................... -- 4.7 .23 8,800
Rochelle................................ 24.9... 4.7 .21 8,750
North Antelope.......................... 35.0 4.7 .24 8,800
Antelope................................ 13.6 5.3 .22 8,800
-----
Total......................... 259.8
- ---------------
Note: Data derived from MSHA and FERC reports.
Total SPRB production has increased rapidly in recent years from
approximately 3 million tons in 1975 to 157 million tons in 1990 and 270 million
tons in 1998.
Operations are gradually moving into more expensive reserves due to a
combination of increasing stripping ratio and greater haul distances. Many
operations are currently in 200 ft - 300 ft of cover and experience stripping
ratios of 2.5 BCY/ton or more. Typically, cash operating costs (before
royalties, taxes, and depreciation) are in the range of $1.75 - $3.00 per ton.
We believe these costs will gradually increase at a rate of 1% to 2% per year in
real terms.
The SPRB coal supply is capable of growing at a rapid rate to meet demand.
However, there are constraints related to loadout capacity, rail logistics,
industry consolidation, and economics. In situations of rapid demand increase,
some increase in prices due to tightening of supplies can be expected.
The SPRB provides a large, stable alternative fuel source for Colstrip.
Mineable reserves are extensive and sufficient to sustain operations through the
study period and beyond. The mines themselves are efficient low-cost operations,
and, while we believe costs (and prices) will gradually increase, we do not
believe that increase will be prohibitive.
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5.2.3 SPRB Demand
The primary market for SPRB coals is and will continue to be electric power
generators. Future fueling decisions by the electrical generating industry will
be influenced by a number of factors, including:
- Deregulation
- Clean Air Act Amendments (CAAA)
- Sulfur dioxide limitations
- NO(x) emission reductions.
Some, if not all, of these issues favor burning SPRB coal for electrical
generation. The desirability of SPRB coal for these reasons will result in
significant future demand growth, particularly in the 2000 - 2005 period, as
CAAA Phase 2 requirements become effective. BOYD estimates demand for SPRB coal
will increase to 330 million tons in 2000, and 415 million tons in 2010. Growth
is projected to moderate after about 2015 due to uncertainty in future
environmental regulation and lack of planned new coal-fired capacity. The mines
in the SPRB will generally be able to satisfy this demand growth, although some
tightening of supplies, particularly in the 2000 - 2005 period, is likely.
5.2.4 SPRB Prices
The Colstrip Station, if it were to purchase SPRB coal, would most likely
take that coal from the mines producing 8,300 - 8,500 Btu/lb coal. The higher
Btu coals carry a price premium related to savings in transportation costs,
which would not be realized over the relatively short rail haul to Colstrip.
Projected FOB mine prices for the lower Btu coals are summarized:
8,400 BTU/LB
YEAR 1998 $/TON
- ---- ------------
2000........................................................ 4.25
2001........................................................ 4.60
2002........................................................ 4.85
2003........................................................ 5.00
2004........................................................ 5.25
2005........................................................ 5.35
2006 on..................................................... 5.40
Expected price increases in the 2000 - 2005 time frame result from
increased demand in that period, largely as a result of CAAA Phase 2. Beyond
that date, we do not anticipate major price increases in real terms.
5.3 TRANSPORTATION
SPRB coal, with only minor exceptions, moves to market via rail. Rail
transportation costs are very significant to the economics of SPRB coal,
typically constituting 50% to 80% of the delivered fuel costs. The ability of
the railroads to lower rates, particularly on longer hauls, has been a key
factor in the growth of the SPRB.
Two railroads compete for SPRB originations, the Union Pacific-Southern
Pacific (UPSP) and the Burlington Northern-Santa Fe (BNSF). Both railroads serve
the mines south of Gillette, while the mines north of Gillette are captive to
the BNSF. Traditionally, the mines served by both railroads have enjoyed lower
rail rates because of the competitive situation. However, recent consolidation
among suppliers and a more competitive posture by the BNSF has minimized this
differential.
Corette and Colstrip are both captive to the BNSF. Although this captive
situation is not as great a disadvantage as in the past, it is still a
consideration which will impact transportation cost to those plants.
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The bulk of SPRB coal movements are under terms of contracts between the
railroads and shippers. Very little tonnage moves under public tariff. While
regulatory agencies (primarily the federal Surface Transportation Board) place
some limitations on rates the railroads can charge, these tend to be at higher
levels than are typically arrived at through negotiation. Coal movements to
Corette, and potentially to Colstrip, would be the result of negotiations
between the BNSF and the utility. Factors that would affect such negotiations
include:
- Volume. Higher volume movements of one to two million tons/year or more
generally enjoy lower rates. The large volumes involved at Colstrip would
be an advantage.
- Distance. Longer hauls are lower-cost on a ton-mile basis. Rail
distances to Corette (253 miles) and Colstrip (360 miles) are
comparatively short for SPRB movements.
- Competition. If there is effective competition from alternative carriers
or other fuel sources, lower rates are possible. This would not be the
case for Colstrip and Corette.
Typically, high-volume, long-distance (1,000 miles or more) movements are
relatively low-cost, in the range of $0.01/ton-mile. Shorter movements of 500
miles or less can be significantly more expensive on a ton-mile basis, ranging
from $0.015/ton-mile to $0.025/ton-mile or more.
The transportation infrastructure to move SPRB coal to Corette and, if need
be, to Colstrip is in place and proven. We are unaware of any circumstances that
would impair the railroad's ability to deliver to the stations, either in the
near term or very long term (through 2048) at Colstrip. Current trends are
towards more efficient railroad operations and lower costs. The cost of coal
movements to Corette and Colstrip would be the subject of negotiations with the
railroad.
5.4 CORETTE STATION FUEL SUPPLY
The Corette Station, located near Billings, Montana, is fueled by coal
purchased from the SPRB, and transported via rail to the plant. It is
anticipated that Corette will continue to be fueled by SPRB coal for the
duration of the study period. Prices are essentially at market, and
transportation agreements remain to be negotiated.
The Corette Station requires a relatively low-sulfur coal, equivalent to
0.60 lbs SO(2)/MMBtu, to meet emissions regulations. This is lower than the
average sulfur at most of the northern, low-Btu SPRB mines; however, those mines
can generally use selective mining techniques to supply a limited amount of
lower sulfur coal. Alternatively, an acceptable low-sulfur coal is available
from several mines (at a premium of $1.00/ton or more) in the southern,
higher-Btu portion of the SPRB Corette is currently receiving coal from this
source under contract which allows the supplier to provide coal from either
area. The specifics of the Corette fuel supply situation are discussed in detail
in the Fuel Cost chapter of this report.
5.5 OTHER SUPPLY SOURCES
Other potential supply sources exist for both Colstrip and Corette;
however, most are not established operations, and there are questions of coal
quality and cost.
These other sources include:
- Bull Mountains. The Bull Mountains coal field is located 35 miles north
of Billings in Yellowstone and Musselshell Counties. Burlington
Resources, Inc., owns a large reserve which could be mined using
underground methods. The property does not have access to rail, but coal
could be trucked to Billings. Issues of cost and quality would require
investigation.
- Tongue River. The Tongue River Region is a large coal field located
about 35 miles southeast of Colstrip. The area has no rail access, and
thus has never been developed. Proposals are in place, however, to
provide rail access either connecting to the BNSF at Miles City or via an
extension of the Colstrip spur. If development in the Tongue River field
takes place, it could provide an alternative supply for the Colstrip
Station.
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- Big Sky. The Big Sky Mine is located just south of WECO's Rosebud Mine
and recovers coal from the same seam. Big Sky is close enough to deliver
coal directly to the Colstrip Station (via over-the-road truck). Big Sky
would have capacity and cost constraints, but could be viable in an
emergency.
- Other Rosebud Seam Resources. Extensive Rosebud Seam resources exist
southeast of Colstrip. These could be developed as a long-term supply,
but would require investment in mine and transportation facilities.
In general, none of these alternatives is as attractive as the established
mines in the SPRB. However, over the plant lifetime through 2048, one of these
could develop into a viable supply option and/or an alternative to the Rosebud
Mine. Ample alternatives exist to fuel the plant over its projected remaining
life.
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FUEL COSTS
6.1 INTRODUCTION
The long-term cost of fuel to the Colstrip and Corette Stations is related
to a number of issues. At Corette, which will most likely be fueled by SPRB
coal, market supply, demand, and price, along with transportation costs,
determine the delivered fuel price. At Colstrip, the situation is more complex,
with price affected not only by production costs at the Rosebud Mine, but also
by the specific terms and conditions of various coal sales and transportation
agreements. This chapter analyzes these issues and develops estimates of
resulting long-term fuel costs.
6.2 COLSTRIP -- GENERAL
The Colstrip Station is fueled entirely by coal from WECO's Rosebud Mine,
which is purchased under long-term contracts between WECO and the station
owners. The contracts are full-requirements agreements, making the mine and
station effectively captive to each other. The provisions of these contracts
determine coal price.
The coal supply for Units 1 & 2 is contractually, as well as physically,
separate from that for Units 3 & 4. Historically, the price of coal to Units 3 &
4 has been significantly above that to Units 1 & 2.
There are operational advantages to combining the two coal supplies. In
particular, combining the operations would provide opportunities to blend coal
to provide a more desirable quality for Units 1 & 2. The combined operations
would also allow more efficient utilization of equipment and personnel. However,
the existence of the contracts, differences in quality and price, and a
continuing minority ownership in Units 3 & 4 may make a combination
problematical. For purposes of this study, we have assumed that the coal supply
to Units 1 & 2 remains separate from Units 3 & 4, each being administered under
the respective contracts.
Sales of coal to outside customers, particularly the recent 1.5 MTPY
contract with Minnesota Power, could have some affect on mining plans and costs.
However, the sale will probably not significantly affect coal price due to
allocation mechanisms incorporated in the contracts. If significant additional
outside sales are secured, the ability to supply Colstrip beyond the current
contract term could be affected.
6.3 COLSTRIP UNITS 1 & 2
6.3.1 Existing Contract
Colstrip Units 1 & 2 are fueled by coal from the Rosebud Mine's Area D,
which is delivered directly to the plant. Sales are under provisions of a
long-term agreement signed July 30, 1971.
Key factors affecting future coal supply under this contract include:
- Term. The contract extends through December 31, 2009, with provisions
for extension under mutually agreeable terms.
- Quantity. The contract is for the full requirements of Colstrip Units 1
& 2. Typically, the units take +/-2.6 million tons per year.
- Pricing. Pricing structure is base price plus escalation, with a
commodity price per ton (including labor, M & S, power, profit, etc.) and
a fixed charge per month (depreciation, A & G, etc.). Also included in
the price is an accrual (estimated at $0.10/Ton) for final mine
reclamation. Production taxes and royalties are passed through at cost.
Current delivered prices under this contract are in the range of
$8.00 - $9.00/ton.
- Price Re-opener. A price re-opener will occur on July 30, 2001. If the
parties are unable to agree on Base Price revisions, the matter is to be
arbitrated so as to be "equitable to all parties and . . . shall reflect
the sellers reasonable costs of mining." Thus, the re-opener is
effectively based on costs, not market.
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- Assignment. The buyer's rights under the contract can be assigned only
in conjunction with a sale of the buyer's interest in Units 1 & 2.
Re-openers, such as that in 2001, have occasionally been contentious issues
at Colstrip. There are incentives at the time of the re-opener to renegotiate
the contract, perhaps along lines of the Amended and Restated Units 3 & 4
agreement. However, unlike Units 3 & 4, the Units 1 & 2 price is relatively low
under the current contract, and operating costs will increase significantly late
in the agreement's life. Thus a renegotiation may be disadvantageous for the
plant owners. In estimating future fuel prices for Units 1 & 2, we assume the
current contract remains in force through its normal expiration date (2009), and
that the 2001 re-opener results in only minor price adjustments to reconcile to
actual operating costs. This is a reasonable assumption given the relative
position of the parties, but not a certainty.
In addition to the Coal Supply Agreement, there is an agreement to purchase
synfuel produced at Entech's (WECO's parent) Advanced Coal Conversion Process
(ACCP) plant for use in Units 1 & 2. The synfuel is priced equal to the variable
cost of Area D coal on a MMBtu basis. There is also a bonus arrangement based on
a proportional rebate of savings that may occur at the plant as a result of
burning the synfuel. Synfuel tonnages will likely be low, on the order of
200,000 tons annually.
This synfuel agreement is structured such that the net fuel price
approximately equals the price of supplying an energy-equivalent amount of coal.
Thus for purposes of fuel price estimates, we assume the total fuel expense will
be essentially the same whether or not some portion is actually synfuel.
The ACCP synfuel plant operation realizes certain significant tax
advantages that expire in 2007; the plant will most likely close at that time.
The existing coal supply agreement precludes purchasing outside (i.e.,
SPRB) coal through its expiration in 2009. Upon expiration, the contract may be
extended "on terms mutually agreeable to the Seller and Buyers, reflecting then
existing market conditions for such existing . . . (Rosebud) . . . coal." The
contract does not contain language that clearly obligates either party to reach
a mutual agreement on contract extension. It is probable that, upon contract
expiration in 2009, WECO would effectively have no further obligations to the
Units 1 & 2 owners.
6.3.2 Units 1 & 2 Supply Reliability
Our review indicates that sufficient recoverable, proven and probable
reserves remain in Area D to satisfy requirements of the current contract
through expiration in 2009. Late in the term, the mine will incur higher costs
due to deep cover and will encounter an area of relatively high sodium coal. The
higher costs will not affect the price of coal due to the contract's base price
plus escalation cost structure.
The higher-sodium coal (in excess of 1% NaO(2) in ash), which will be
encountered in 2008 and later, will meet contractual quality specifications
(there is no specific limit on sodium). However, high-sodium coal has caused
difficulties in Units 1 & 2 in the past, and may do so in this instance. The
potential problem could be avoided by blending with lower sodium (Area C) coals,
substituting reserves, or some combination of measures.
Certain equipment and facilities at Mine Area D are, as discussed in
Chapter 4, adequate for current operations but are relatively old. Substantial
capital investment is required in the 2000 - 2002 period to assure reliable
operation over the remaining contract term. We assume WECO will be reluctant to
make major investments in new, long-lived equipment and facilities with only
+/-9 years remaining on the contract. Therefore, the projected investments are
assumed to be mostly in overhauls, rebuilds, and other "stop-gap" expenditures
with relatively short depreciable lifetimes. This investment will increase the
price of coal by $0.10 - 0.15/ton via the depreciation component of the fixed
charge.
6.3.3 Units 1 & 2 Existing Contract Fuel Costs
We estimated future fuel prices under the existing contract, considering
the contractual pricing parameters and likely future events. The 2001 re-opener
will have some effect on price, as certain price
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337
components may vary from actual costs. Although there is considerable
uncertainty, we have assumed a limited price cut will result from the re-opener.
We do not expect the sale of coal to Minnesota Power to significantly affect
contract price.
Estimated fuel costs under the existing contract are shown on Table 6.1
following this text, and summarized below (1998 dollars):
UNITS 1 & 2 DELIVERED FUEL PRICE (1998 DOLLARS)
-----------------------------------------------------
2003 -
1999 2000 2001 2002 2009 AVERAGE
----- ----- ----- ----- ------ -------
Tons/Yr (000)..................... 1,510 3,020 3,020 3,020 3,020 3,020
Quality -- Btu/lb................. 8,558 8,558 8,558 8,558 8,558 8,558
Contract Price ($/Ton):
Commodity Charge................ 5.79 5.78 5.78 5.19 5.31 5.41
Fixed Charge.................... 1.31 1.39 1.42 1.44 1.48 1.46
Royalties*...................... 1.04 1.04 1.05 0.96 0.98 1.00
Quality Adjustment.............. (0.14) (0.14) (0.14) (0.13) (0.13) (0.13)
----- ----- ----- ----- ----- -----
Total................... 8.00 8.07 8.11 7.46 7.64 7.72
Fuel Price ($/MMBtu).............. 0.47 0.47 0.47 0.44 0.45 0.45
- ---------------
* Includes production taxes associated with royalty payments.
The cost estimates, as shown, assume a price cut as a result of the 2001
re-opener, roughly reconciling price to costs at that time. Our analysis of mine
operations also indicates that mining costs will increase significantly in the
last 2 - 3 years of the contract term. Under the current contract format, this
increase will not be reflected in the price and will reduce WECO's profits.
6.3.4 Units 1 & 2 Long-Term Fuel Cost
Beyond the expiration date of the current contract, the fuel source for
Units 1 & 2, and therefore the price, is speculative. We developed estimates of
price based on reasonable assumptions about future events as outlined below.
It is reasonable to assume the current supplier relationship will be
extended at (or before) expiration of the current contract. However, the
"market" price for "such existing coal" as stated in the contract will be
indefinite, since the only other currently identifiable market for such coal is
Units 3 & 4. The reserves available at Rosebud for an extension will also be
more costly to mine. Thus the outcome of price negotiations for any extended
term is uncertain. For purposes of this study, we have assumed:
- The contractual relationship with WECO will be extended for the entire
study period (i.e., through 2030).
- A new contract structure will be negotiated for Units 1 & 2 similar to
the Amended and Restated supply agreement for Units 3 & 4. This "cost
plus" pricing structure is acceptable to WECO and provides reasonable
compensation and profit, while allowing the station owners considerable
control over the operation.
- The pricing structure under a new contract would be designed to assure
delivered fuel costs are equal to or less than the delivered cost of
alternative (SPRB) fuel. This competitive benchmark is assumed to be
$0.65/MMBtu.
- Existing reserves in Areas A and B would be dedicated to the contract,
and delivered directly to the existing coal handling facility.
- Operations supplying fuel to Units 1 & 2 would continue to be physically
separate from the Units 3 & 4 supply.
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This revised and extended contract would result in an increase in fuel
costs due to increased costs at the mine, and capital investment needed to
operate over the extended contract term.
Estimated delivered fuel costs for Units 1 & 2 over the 2010 - 2030 period
are shown on Table 6.1 following this text, and are summarized below (1998
dollars):
AVERAGE
2010 - 2030
-----------
Tons/Yr (000)............................................... 2,964
Quality (Btu/lb)............................................ 8,728
Coal Price ($/Ton)
Fixed Charge.............................................. 1.66
Commodity Charge
Mine Operating Expense................................. 4.26
Return on Investment................................... 0.54
Fees................................................... 0.55
Royalties & Production Taxes........................... 3.69
-----
Subtotal.......................................... 9.04
Total Price....................................... 10.70
Price per MMBtu........................................ 0.61
The price is relatively consistent over the study period, but does
gradually increase from +/-$10.50/ton in the early years to over $11.00/ton late
in the period. These increases relate to increases in mining costs as operations
progress into deeper cover areas. Resource depletion as a result of third party
sales could increase prices further late in the study period.
6.4 COLSTRIP UNITS 3 & 4
6.4.1 Units 3 & 4 -- Existing Coal Supply Contract
Colstrip Units 3 & 4 are fueled by coal from Area C, which is transported
to the plant via a 4.2-mile conveyor owned and operated by WECO. Sales are
governed by an agreement originally signed in 1980, and extensively amended in
1998. The August 24, 1998, "Amended and Restated Coal Supply Agreement"
significantly changes the terms and provisions of the original 1980 contract
(which was similar in form to the Units 1 & 2 agreement) by changing to a cost
plus pricing structure and eliminating future re-openers. The new contract will
result in a significant price decrease estimated at +/-$4.00/ton. This decrease
will be phased in over a two-year period, taking full effect on July 1, 2000.
Prior to that time, the old pricing structure will remain, with labor and ad
valorem tax cost components limited to actual amounts.
Key provisions affecting future coal supply and costs include:
- Term. The contract terminates on December 31, 2019. The parties can, by
mutual agreement, extend the contract beyond that date, but there is no
obligation to do so.
- Quantity. The contract is for the full requirements of Units 3 & 4. The
agreement provides for WECO to substitute outside coal for Rosebud Mine
coal under certain conditions.
- Pricing. Pricing structure is cost plus, including certain fees,
incentives, and return on investment compensation.
- Administrative Structure. The Amended and Restated Contract provides for
a Mine Operating Committee to monitor the mine operation, approve
budgets, review plans, etc. Effectively, the station owners control major
planning and investment aspects of the mine while WECO manages day-to-day
operations.
- Assignment. In general, the buyer's rights under the coal supply
agreement can be assigned only as part of a sale of the buyer's interest
in the generating station. Special provisions apply relative to
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Montana Power's obligations guaranteeing WECO's performance of final
reclamation work. Montana Power cannot assign this obligation except with
the consent of the other owners.
Sufficient recoverable proven and probable coal reserves remain in Area C
for the duration of the contract, and Area C will be essentially depleted when
the contract expires. Additional reserves are available farther west in Area F,
but are not committed to Units 3 & 4.
Under the Amended and Restated contract, all coal requirements for Units 3
& 4 must be purchased under terms of the contract, but those terms provide for
the purchase of coal from outside sources (probably from the SPRB). Should
outside coal be purchased, WECO is entitled to add certain fees to the selling
price and will recover certain fixed costs (depreciation, return on investment,
etc.) in full, irrespective of outside coal purchases. Based on our estimates of
Rosebud fuel costs and that from alternative sources, we consider it unlikely
that any significant tonnage of third party coal could be economically purchased
in the normal course of dealing under the Amended and Restated Contract.
Upon termination in 2019, the contract can be extended by mutual agreement.
If the parties are unable to agree, the contract terminates. Thus, WECO has no
obligation to continue supplying coal beyond 2019, and the Units 3 & 4 owners
have no legal right to any reserves beyond that date. Should the contract not be
extended, coal from the SPRB could provide a viable, competitive alternative
fuel supply for the balance of the study period and beyond.
6.4.2 Units 3 & 4 Coal Transportation Agreement
WECO's operation of the 4.2-mile overland conveyor which delivers Area C
coal to Units 3 & 4 is under a separate agreement with the owners of Units 3 &
4. That agreement was initially negotiated in 1981; it was amended in 1987 and
again in 1998. The 1998 amendment significantly alters the economic parameters
of the agreement, reducing the price, and eliminates future price re-openers.
Key provisions of the amended agreement are:
- Term. The transportation agreement remains in force for so long as the
Units 3 & 4 Coal Supply Agreement continues, i.e., through 2019. The
contract can be extended by mutual agreement.
- Quantity. All coal sold under the Coal Supply Agreement (from Area C)
will be transported via the conveyor.
- Price. Under the 1998 amendment, effective July 1, 2001, the price is
the sum of the actual costs to operate the conveyor, fixed charges such
as depreciation, taxes, etc., and a "Fee-Operating Profit" of $0.58/Ton
indexed for inflation.
- Other Terms. The 1998 amendment eliminates re-openers in 2001, 2006, and
2011, and deletes the gross inequity provision.
- Assignment. Can be assigned by buyer only in conjunction with an
assignment of rights under the Coal Supply Agreement.
The price revisions incorporated in the amendment will result in a decrease
in transportation cost of about $0.70/ton from $1.60 - $1.65/ton to
$0.90 - $0.95/ton. The higher price remains in effect until the new price is
phased in on July 1, 2001.
The amended contract provides the station owners considerable control over
operating decisions affecting the conveyor, particularly as relates to capital
expenditures. We anticipate that future capital expenditures on the conveyor
will be minimal, mostly related to replacements and major rebuilds.
6.4.3 Units 3 & 4 Existing Contract Price
The Amended and Restated Contract provides for a phasing in of the new
"cost plus" pricing structure. Approved capital expenditures made after January
1, 1999, will be incorporated into the capital investment base. The basic "cost
plus" pricing structure becomes effective on July 1, 2000, and the Fixed Fee
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($0.40/ton) is implemented on July 1, 2001. Prior to July 1, 2000, the old
pricing (a "base price plus escalation" structure) remains in place with certain
limitations on labor cost and property taxes.
Mining equipment in Area C is relatively old and will require rebuilding or
replacement in the near future. WECO has a five-year $40 million capital budget
(including an additional dragline to be moved from Area A) for this purpose.
These expenditures will affect coal price under the Amended and Restated
Agreement via depreciation and return on investment provisions of the contract.
The Amended and Restated Agreements create a funding mechanism for final
reclamation expenses at the Rosebud Mine. Under this mechanism, WECO takes the
responsibility for final reclamation expenses, except for Puget Sound Power &
Light's proportional (25%) share. (Puget's share is assumed to continue as an
accrual equal to 25% of the appropriate total accrual on a per-ton basis.) The
contractual funding mechanism requires Montana Power to effectively guarantee
WECO's performance in this area.
The Amended and Restated Agreement gives the Units 3 & 4 owners strong
rights over mining plans, capital expenditures, and budgets. The contract also
dictates a "least cost" mining approach which will result in relatively low
costs in the initial years of the contract, with gradual increases over the
contract term. These gradually increasing mining costs will, with the "cost
plus" structure, result in gradually increasing coal prices. Estimated fuel
prices under the Amended and Restated Agreement are shown on Table 6.1, and
summarized below (1998 dollars):
UNITS 3 & 4 DELIVERED FUEL PRICE (1998 DOLLARS)
--------------------------------------------------------
1999 2000 2001 2002 2003 - 19 AVERAGE
----- ----- ----- ----- --------- -------
Tons/Yr (000)................... 3,485 6,971 6,971 6,971 6,971 6,971
Quality -- Btu/lb............... 8,509 8,509 8,509 8,509 8,509 8,509
Contract Price ($/Ton)
Commodity Charge.............. 9.52 7.35 5.91 6.24 6.91 6.92
Fixed Charge.................. 0.68 0.91 1.14 1.18 1.37 1.31
Royalties*.................... 1.70 1.44 1.17 1.23 1.37 1.36
----- ----- ----- ----- ----- -----
Subtotal................... 11.90 9.70 8.22 8.65 9.65 9.59
Transportation ($/Ton)........ 1.62 1.62 1.27 0.91 0.92 0.99
Total Cost:
$/Ton......................... 13.52 11.32 9.49 9.56 10.57 10.58
$/MMBtu....................... 0.79 0.67 0.56 0.56 0.62 0.62
- ---------------
* Includes production taxes associated with royalty payments.
Delivered fuel price projections could be affected by third party sales
(Minnesota Power); however, the structure of the contract will serve to minimize
this impact.
6.4.4 Units 3 & 4 Estimated Price -- Extended Term
Following expiration in 2019, the contract can be extended by mutual
agreement. Although there is no assurance, it appears likely that WECO would
have reserves available for such an extension in Area F.
For purposes of estimating fuel prices to Units 3 & 4 after 2019, we have
assumed that the present contract will be extended on terms and conditions
similar to those currently in the agreement, and that WECO will dedicate Area F
to Units 3 & 4. This is a reasonable assumption given the current lack of other
markets for WECO's coal. The initial mining in Area F is relatively low-cost, as
shallow reserves are available, but will increase over time as deeper overburden
and longer haul distances affect prices.
Our review indicates that prices under this extended contract will be in
the same range, or possibly higher than the delivered cost of coal from the
SPRB. In estimating these long-term fuel costs, we have assumed that WECO will
make concessions in the form of reduced profits to assure the Rosebud coal is
priced competitively with SPRB coal. This pricing benchmark is estimated at
$0.65/MMBtu delivered to the plant.
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Contract costs are for delivery to the Area C tipple. Additional expense
will be incurred conveying the coal from Area C to the power plant. Our
estimates assume the current transportation contract pricing structure, as
amended, will remain in place for the entire study period (through 2030). That
structure incorporates a 15% discount of certain price components after 120.5
million tons have been delivered. At projected production rates, this occurs in
2018.
Projected fuel costs for Units 3 & 4 after 2019 are shown on Table 6.1 and
summarized below (1998 dollars):
AVERAGE
2020 - 2030
-----------
Tons/Yr (000)............................................... 6,900
Quality (Btu/lb)............................................ 8,591
Fob Mine Price ($/Ton):
Commodity Charge.......................................... 6.79
Fixed Charge.............................................. 1.28
Royalties*................................................ 1.34
-----
Subtotal............................................... 9.41
Transportation ($/Ton).................................... 0.78
Total Cost:
$/Ton..................................................... 10.19
$/MMBtu................................................... 0.59
- ---------------
* Includes production taxes associated with royalty payments.
6.5 COLSTRIP -- ALTERNATIVE SUPPLY POTENTIAL
The availability of relatively low-priced coal from the SPRB provides
Colstrip an alternative to the Rosebud Mine for fuel supply. This is addressed
in general in the "Alternative Supplies" chapter of this report; specific impact
at Colstrip is discussed in this section.
6.5.1 Alternative Supply Issues
Bringing SPRB coals to Colstrip raises a number of issues. These include:
- Transportation. Coal would move to Colstrip by rail via the BNSF. Rail
distance from Gillette, Wyoming, to Colstrip is approximately 350 miles,
and the movement would be captive to the BNSF.
- Coal Handling. The Colstrip Station is not equipped to receive coal by
rail in significant volumes. SPRB coal delivered prices would have to
include the capital and operating costs associated with a coal receiving
facility.
- Plant Design. The Colstrip plant is designed specifically for Rosebud
coal; the operational impact of burning SPRB coal is unknown. We would
expect the impact to be minimal due to the general similarity of the
coals; thus, we have not considered any impacts in this study.
- Units 1 & 2 Contract. The existing contract would preclude purchasing
any SPRB coal for Units 1 & 2 prior to January 1, 2010. SPRB coal could
be a viable option after that time.
- Units 3 & 4 Contract. The current Units 3 & 4 contract allows purchase
of outside coal, but specifies certain payments to WECO that would add to
the delivered cost. Outside coal could be purchased without these
payments beginning January 1, 2020, following expiration of the contract.
All of these issues impact the economics of any alternative outside
supplies, and must be considered in assessing the viability of such a supply.
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6.5.2 SPRB Prices
As discussed in the Alternative Supplies chapter of this report, the most
economical SPRB sources for Colstrip are likely to be the lower quality +/-8,400
Btu/lb coal mines in the northern portion of the SPRB. BOYD's long-term
projections of prices at these mines increase from a projected $4.25/ton (1998
dollars) in 2000 to $5.40/ton in 2006, remaining constant in real terms
thereafter.
6.5.3 Transportation Costs
Transportation to Colstrip will be via the BNSF, a distance of
approximately 360 miles. Typically, such movements are under contracts
negotiated between the shipper and the BNSF. The precise outcome of such a
negotiation regarding Colstrip is unknown and subject to considerable
uncertainty due to the specifics of the movement, including:
- At 350 miles, the movement is fairly short as compared to most SPRB
hauls. Shorter hauls are typically less efficient and more costly on a
ton-mile basis.
- The haul is captive to the BNSF as delivering carrier and probably as
originating carrier. This places the BNSF in a strong position in rate
negotiations.
- The potential volume, at +/-10 million tons per year, is very large and
would represent an attractive business for the BNSF.
- The route, particularly from Gillette to Huntly, Montana (near Billings),
is relatively uncongested, resulting in minimal delays in transit.
Considering these factors, we estimate the cost of rail transportation from
the Gillette area at $6.05 per ton. This estimate includes the carrier charge
and an allowance for ownership and maintenance costs on the required cars.
6.5.4 Coal Handling
To take SPRB coal, the Colstrip Station would have to construct a coal
receiving facility and integrate that facility into the existing coal handling
infrastructure. The capital and operating costs for such a facility could vary
significantly depending on specific design criteria. For purposes of comparative
fuel cost estimates for this study, we have assumed a total cost, including
facility depreciation and operating cost, of $0.25/ton.
6.5.5 WECO Charges
Under the Units 1 & 2 coal supply contract, no outside coal could be
purchased for those units prior to expiration in 2009. After that time, outside
coal could be purchased with no fee or other payment to WECO.
For Units 3 & 4, the purchase of outside coal under the current contract
would require certain compensation to WECO, both in the form of a specific fee,
and fixed payments dictated by contract irrespective of the tonnage produced at
Rosebud. These include:
- Average Fixed Fee Per Ton ($0.40/ton) on each ton of outside coal
purchased.
- Earned portion of the "Incentive Fee Per Ton" (base $0.35/ton) on each
ton of outside coal purchased.
- Per-Ton Return on Investment (ROI) paid on a pro-rata basis on the first
5 million tons purchased, whether those tonnages are Rosebud or outside
coal. In effect, outside coal must bear its proportional per-ton share of
the ROI charge.
- Conveyor "Fee-Operating Profit" of $0.54/ton under the Amended
Transportation Agreement is paid on all coal sold under the contract,
whether by WECO or a third party.
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These estimated WECO charges averaged over the life of the Units 3 & 4
contract are summarized (1998 dollars):
2000 - 2019
AVERAGE
CHARGE $/TON
- ------ -----------
Fixed Fee................................................. 0.37
Incentive Fee............................................. 0.28
ROI Charge................................................ 0.72
Conveyor Fee.............................................. 0.58
----
Total........................................... 1.95
The actual WECO charge allocated to outside purchases varies from year to
year, and could depend on the relative proportions of Rosebud and outside coal.
The above figure is, however, reasonable for comparative purposes.
6.5.6 Total Cost of Alternative Fuel
The comparative cost of SPRB coal delivered to the Colstrip station is
summarized (1998 dollars):
UNITS 3 & 4
UNITS 1 & 2 -------------------------
COST AFTER 2009 2000 - 2019 AFTER 2019
- ---- ----------- ----------- ----------
FOB Mine Price (Average).................. 5.40 5.25 5.40
Rail Transport............................ 6.05 6.05 6.05
Handling.................................. 0.25 0.25 0.25
WECO Charges.............................. -- 1.95 --
----- ----- -----
Total........................... 11.70 13.50 11.70
$/MMBtu @ 8,400 Btu/lb.................... 0.70 0.80 0.70
As shown, the cost of SPRB coal delivered to Units 3 & 4 under the current
contract is likely to be significantly more expensive than Rosebud coal (at
$0.60 to $0.65 per MMBtu), largely due to the added WECO charges.
After termination of the current contracts, SPRB supplies could be
delivered to Colstrip at prices in the range of $0.70/MMBtu, or perhaps, given
the uncertainties in the estimates, for as little as $0.60 to $0.65 per MMBtu.
For purposes of this study, we have assumed that Rosebud coal would have to be
priced at a delivered cost of less than $0.65 per MMBtu to be competitive with
the SPRB after expiration of the existing contracts.
While it appears that SPRB coal will not be an economical replacement for
Rosebud coal over the study period, the potential to purchase SPRB coal
effectively caps the post-contract fuel cost for Colstrip.
6.5.7 Long-Term Fuel Alternatives
The Colstrip plant is expected to continue operation beyond the specific
study period addressed in this report, with current plans extending to 2048.
Projections for the 2030 - 2048 period would be highly speculative and are not
developed herein. However, there are certain long-term factors affecting fuel
supplies beyond 2030 that can be addressed. These include:
- Fuel Source. Economically recoverable coal at the Rosebud Mine will
likely be depleted in 2030 or perhaps earlier. Several alternative coal
sources are likely to be available at that time (discussed in Chapter 5),
with the most likely source being the SPRB. Available reserves in the
SPRB are, based on current projections, likely to be adequate to fuel
Colstrip over the 2030 - 2048 period.
- Delivery. Coal would most likely be delivered to Colstrip via rail,
specifically by the BNSF. The existing rail infrastructure is in-place,
and we are unaware of any circumstances that would impair the ability of
the railroad to deliver adequate volumes of coal. Projections of rail
rates to 2030 and beyond
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are not meaningful; however, the recent trend is towards lower rail
rates. We would not expect this to continue indefinitely; however, we
would also not expect a major reversal towards significantly higher
rates.
- Plant Modifications. Receiving SPRB coal via rail would require
construction of a receiving facility, and probably some modifications to
coal handling facilities, all of which appear feasible. The cost of these
unloading facilities would depend on specific design criteria and ability
to integrate with the existing system. Assuming the existing WECO spur,
loop track, and conveyor facilities are available, and that no major
surge storage is needed, we estimate the facility cost in the range of
$10 million. Surge capacity and/or throughput improvements could increase
this by $5 million to $7 million, and a fully independent facility could
range up to $25 million.
Modifications needed to the plant itself are beyond the scope of BOYD's
study; however, given the general similarities between the coals, we
would not anticipate major new investment.
In general, adequate and feasible fuel supplies appear to be available for
the Colstrip Station for the 2030 - 2048 period.
6.6 CORETTE
The Corette Station, located near Billings, Montana, is fueled by coal
purchased from the SPRB, and transported via rail to the plant. It is
anticipated that Corette will continue to be fueled by SPRB coal for the
duration of the study period.
6.6.1 Fuel Supply Source
The Corette Station currently buys coal under provisions of a short-term
agreement with Caballo Coal Company, a subsidiary of Peabody Holding Company
(Peabody). The contract extends through December 31, 1999, and specifies
delivery of 750,000 tons during 1999.
The coal was traditionally supplied by the Rawhide Mine in Campbell County,
Wyoming, which is owned and operated by a Peabody affiliate. Quality
specifications call for a relatively low-sulfur coal, which Rawhide produced via
selective mining within the seam horizon. These specifications are:
EXPECTED MONTHLY WEIGHTED
AS-RECEIVED SPECIFICATIONS
- -------------------------------------------------------------
Moisture............................................ 30.8%
Ash................................................. 5.0%
Btu/lb.............................................. 8,320
Sulfur.............................................. 0.25%
SO(2)/MMBtu......................................... 0.60lb
By contract, calculated sulfur dioxide on a trainload basis is not to
exceed 0.60 lbs/MMBtu. This low sulfur coal is needed to meet emissions
regulations in the Billings area.
Contract price for 1999 is set at $3.65/ton. This is competitive for the
+/-8,400 Btu/lb SPRB coals, and does not appear to carry a significant premium
for the low sulfur. We believe that, in the future, the lower sulfur coal will
carry a small premium due to demand for CAAA compliance.
The base contract was amended to allow coal produced at Peabody's North
Antelope/Rochelle complex to be substituted for Rawhide coal after April 1,
1999. Peabody exercised this option, and has been delivering from North Antelope
since April (the Rawhide Mine has been idled). North Antelope is located at the
southern end of the SPRB and produces a higher quality (8,800 Btu/lb, 0.22%
sulfur) "super compliance" coal. The North Antelope coal is priced at a discount
to current market, and would be delivered to Corette for approximately the same
price per MMBtu as Rawhide.
Future coal supplies will likely continue to be purchased from SPRB Mines.
The traditional supplier, the Rawhide Mine, provides an attractive source due to
the ability to selectively mine a low-sulfur product. Other
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mines in the vicinity of Rawhide (Buckskin and Eagle Butte) also have the
ability to selectively mine a low-sulfur product. If Rawhide is unable to supply
future coal, these nearby mines offer a viable, competitively priced alternative
low-sulfur, low-Btu source.
In the worst case, several mines, such as North Antelope/Rochelle in the
southern, higher-Btu portion of the SPRB could supply coal, meeting the 0.60-lb
SO(2)/MMBtu limit. These coals are higher priced (typically by $1.00/ton or
more) than Corette's current contract price and must be transported farther. The
higher-Btu content offsets some of this expense, but the delivered cost would
still likely be $0.05 to $0.08/MMBtu (or more) higher than for coal supplied
from Rawhide or other nearby mines.
Overall, we believe the SPRB mines will provide a reliable long-term source
of low-sulfur coal for Corette. If Rawhide or nearby suppliers cannot provide
adequate low-sulfur coal, the plant can obtain low-sulfur coal from the
higher-Btu mines in the southern portion of the SPRB at the expense of a small
premium.
6.6.2 Corette Coal Transportation
Coal is currently transported to Corette under two transportation
agreements with the Burlington-Northern Santa Fe Railway. The first agreement is
for coal movements from Rosebud to Corette. Although no coal is moved under the
agreement, a fixed fee of approximately $1.1 million per year is charged. The
second rate agreement is for movements between various Wyoming (SPRB) origins
and Corette. These movements are priced at $5.00 - $6.00 per ton, depending on
origin, plus various supplemental charges. Shipper-owned cars are specified.
Overall transportation cost to Corette (excluding the $1.1 million dollar fixed
fee) are typically in the range of $6.00/ton or $0.024/ton-mile for the 253-mile
haul.
The existing Corette contract was scheduled to terminate June 30, 1999, but
was extended to the end of 1999 to coincide with the termination of the coal
supply agreement. PP&L Montana intends to negotiate a new rail transportation
agreement with substantially different terms prior to that date. The outcome of
these negotiations is unknown at this time. Factors that could affect the
negotiations include:
- The distance involved is relatively short at 253 miles. Variable costs
per ton-mile are higher on short hauls.
- The current rate at +/-$0.025 per ton-mile is relatively high.
- The utility owns 75-cars, which are moved as a unit. Shipper ownership of
cars will result in a lower rate; however, a 75-car train is relatively
short.
- The volume involved, at 750,000 to 800,000 tons per year, is relatively
small. The railroad may not be able to dedicate locomotives to the
movement full-time.
- Corette is captive to the BNSF. There is little effective competition for
fuel deliveries.
We believe a rate reduction can be negotiated, but that reduction will be
limited, given the railroad's negotiating position. Our estimated cost for
transportation of Corette coal is $0.020/ton-mile ($5.06/ton). This considers
savings due to car ownership and maintenance (which is charged to power station
O & M).
6.6.3 Corette Coal Supply -- Delivered Cost
Coal supplies from the SPRB are adequate for Corette over the study period.
Although the sulfur restrictions limit the possible sources, there are
sufficient potential suppliers in both the northern and southern portions of the
SPRB to assure adequate supply alternatives.
Coal costs FOB mine are estimated based on benchmark price projections for
8,400 Btu/lb coal (see Chapter 5). These are adjusted for the lower Btu required
at Corette and a premium for low sulfur content.
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Delivered fuel prices are the sum of the FOB mine price and the
transportation cost. These fuel price estimates are shown on Table 6.1 following
this text, and summarized below (1998 dollars):
DELIVERED PRICE (1998 $)
-----------------------------------------
2001- 2006-
1999 2000 2005 2030 AVERAGE
---- ---- ----- ----- -------
FOB Mine ($/Ton)............................. 3.65 4.10 4.90 5.40 5.23
Transportation ($/Ton)....................... 5.06 5.06 5.06 5.06 5.06
---- ---- ---- ----- -----
Total.............................. 8.71 9.16 9.96 10.46 10.29
$/MMBtu @ 8,330 Btu/lb....................... 0.52 0.55 0.60 0.63 0.62
6.7 FUEL PRICE ESTIMATES -- INFLATED BASIS
Estimated fuel prices over the study period are shown on Table 6.1
(following this text) expressed in 4th quarter 1998 dollars with no allowance
for inflation. Because the fuel price is the sum of a number of components, not
all of which inflate at similar rates (or at all), the delivered fuel cost will
likely lag inflation somewhat. We have therefore developed parallel fuel price
estimates on a nominal (i.e., inflated) dollar basis, as shown on Table 6.2
(following this text). Inflation assumptions incorporated in Table 6.2 are based
on a number of projections which we consider reasonable for the price estimates,
including general inflation (GDP-IPD) of 2% - 3% per year.
Following this text are:
Tables:
6.1: Estimated Fuel Price Summary -- 1998 Dollars
6.2: Estimated Fuel Price Summary -- Inflated Dollars
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TABLE 6.1
ESTIMATED FUEL PRICE -- COLSTRIP & CORETTE STATIONS
1998 DOLLARS -- NO ALLOWANCE FOR INFLATION
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING & GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
1999 2000 2001 2002 2003 2004 2005 2006
------ ------ ------ ------ ------ ------ ------ ------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000).................................. 1,510 3,020 3,020 3,020 3,020 3,020 3,020 3,020
Other Sources (Tons-000)................................. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total.................................................. 1,510 3,020 3,020 3,020 3,020 3,020 3,020 3,020
Avg. Quality (Btu/Lb)...................................... 8,558 8,558 8,558 8,558 8,558 8,558 8,558 8,558
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)................................ 8.00 8.07 8.11 7.46 7.51 7.50 7.50 7.53
Other Sources ($/Ton).................................... -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton......................................... 8.00 8.07 8.11 7.46 7.51 7.50 7.50 7.53
Units 1 & 2 Total Fuel Cost -- $-000....................... 12,078 24,381 24,500 22,541 22,670 22,661 22,647 22,741
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................ 0.47 0.47 0.47 0.44 0.44 0.44 0.44 0.44
------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 1 & 2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 2,261 4,745 4,862 4,909 5,036 5,027 5,013 5,106
Variable Cost:
Per Year ($-000)....................................... 9,816 19,636 19,638 17,632 17,634 17,634 17,633 17,635
Per Ton ($)............................................ 6.50 6.50 6.50 5.84 5.84 5.84 5.84 5.84
Per MMBtu ($).......................................... 0.38 0.38 0.38 0.34 0.34 0.34 0.34 0.34
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000).................................. 3,485 6,971 6,971 6,971 6,971 6,971 6,971 6,971
Other Sources (Tons-000)................................. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total.................................................. 3,485 6,971 6,971 6,971 6,971 6,971 6,971 6,971
Avg. Quality (Btu/Lb)...................................... 8,509 8,509 8,509 8,509 8,509 8,509 8,509 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)............................... 11.90 9.70 8.22 8.65 8.77 9.15 9.33 9.55
Transportation Cost ($/Ton)............................ 1.62 1.62 1.27 0.91 0.92 0.92 0.92 0.93
------ ------ ------ ------ ------ ------ ------ ------
Subtotal............................................. 13.52 11.32 9.49 9.56 9.69 10.07 10.25 10.48
Other Sources ($/Ton).................................... -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton........................................... 13.52 11.32 9.49 9.56 9.69 10.07 10.25 10.48
Units 3 & 4 Total Fuel Cost -- $-000....................... 47,122 78,910 66,166 66,675 67,517 70,168 71,485 73,063
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................ 0.79 0.67 0.56 0.56 0.57 0.59 0.60 0.62
------ ------ ------ ------ ------ ------ ------ ------
2007 2008 2009 2010 2011 2012 2013 2014
------ ------ ------ ------ ------ ------ ------ ------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000).................................. 3,020 3,020 3,020 3,020 3,020 2,957 2,957 2,957
Other Sources (Tons-000)................................. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total.................................................. 3,020 3,020 3,020 3,020 3,020 2,957 2,957 2,957
Avg. Quality (Btu/Lb)...................................... 8,558 8,558 8,558 8,558 8,558 8,740 8,740 8,740
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)................................ 7.85 7.83 7.82 10.34 10.12 10.06 10.40 10.59
Other Sources ($/Ton).................................... -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton......................................... 7.85 7.83 7.82 10.34 10.12 10.06 10.40 10.59
Units 1 & 2 Total Fuel Cost -- $-000....................... 23,692 23,641 23,629 31,230 30,554 29,741 30,765 31,317
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................ 0.46 0.46 0.46 0.60 0.59 0.58 0.60 0.61
------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 1 & 2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 5,140 5,090 5,078 10,564 10,856 11,112 11,472 11,547
Variable Cost:
Per Year ($-000)....................................... 18,552 18,551 18,551 20,666 19,698 18,629 19,293 19,770
Per Ton ($)............................................ 6.14 6.14 6.14 6.84 6.52 6.30 6.52 6.69
Per MMBtu ($).......................................... 0.36 0.36 0.36 0.40 0.38 0.36 0.37 0.38
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000).................................. 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971
Other Sources (Tons-000)................................. -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total.................................................. 6,971 6,971 6,971 6,971 6,971 6,971 6,971 6,971
Avg. Quality (Btu/Lb)...................................... 8,509 8,509 8,509 8,509 8,509 8,509 8,509 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)............................... 9.45 9.55 9.65 9.83 10.00 9.99 9.87 9.82
Transportation Cost ($/Ton)............................ 0.93 0.93 0.93 0.93 0.92 0.92 0.92 0.92
------ ------ ------ ------ ------ ------ ------ ------
Subtotal............................................. 10.38 10.48 10.58 10.76 10.92 10.91 10.79 10.74
Other Sources ($/Ton).................................... -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton........................................... 10.38 10.48 10.58 10.76 10.92 10.91 10.79 10.74
Units 3 & 4 Total Fuel Cost -- $-000....................... 72,337 73,045 73,773 74,986 76,129 76,074 75,207 74,891
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................ 0.61 0.62 0.62 0.63 0.64 0.64 0.63 0.63
------ ------ ------ ------ ------ ------ ------ ------
2015
------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000).................................. 2,957
Other Sources (Tons-000)................................. --
------
Total.................................................. 2,957
Avg. Quality (Btu/Lb)...................................... 8,740
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)................................ 10.90
Other Sources ($/Ton).................................... --
------
Total -- $/Ton......................................... 10.90
Units 1 & 2 Total Fuel Cost -- $-000....................... 32,243
------
--$/MMBtu............................ 0.62
------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 1 & 2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 11,805
Variable Cost:
Per Year ($-000)....................................... 20,439
Per Ton ($)............................................ 6.91
Per MMBtu ($).......................................... 0.40
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000).................................. 6,971
Other Sources (Tons-000)................................. --
------
Total.................................................. 6,971
Avg. Quality (Btu/Lb)...................................... 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)............................... 9.79
Transportation Cost ($/Ton)............................ 0.92
------
Subtotal............................................. 10.71
Other Sources ($/Ton).................................... --
------
Total -- $/Ton........................................... 10.71
Units 3 & 4 Total Fuel Cost -- $-000....................... 74,639
------
--$/MMBtu............................ 0.63
------
6-13
348
1999 2000 2001 2002 2003 2004 2005 2006
------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 3 & 4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 3,899 14,956 23,181 23,649 24,060 25,127 25,771 26,228
Variable Cost:
Per Year ($-000)....................................... 43,223 63,954 42,985 43,026 43,456 45,040 45,714 46,835
Per Ton ($)............................................ 12.40 9.17 6.17 6.17 6.23 6.46 6.56 6.72
Per MMBtu ($).......................................... 0.73 0.54 0.36 0.36 0.37 0.38 0.39 0.39
CORETTE STATION
Coal Purchased (Tons -- 000)............................... 405 810 810 810 810 810 810 810
Avg. Quality (Btu/Lb)...................................... 8,330 8,330 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)............................... 3.65 4.10 4.45 4.70 4.90 5.15 5.30 5.40
Transportation Cost ($/Ton).............................. 5.06 5.06 5.06 5.06 5.06 5.06 5.06 5.06
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton........................................... 8.71 9.16 9.51 9.76 9.96 10.21 10.36 10.46
Corette Total Fuel Cost* -- $-000.......................... 3,528 7,420 7,703 7,906 8,068 8,270 8,392 8,473
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................... 0.52 0.55 0.57 0.59 0.60 0.61 0.62 0.63
------ ------ ------ ------ ------ ------ ------ ------
2007 2008 2009 2010 2011 2012 2013 2014
------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 3 & 4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 25,823 25,617 25,394 25,586 25,871 25,768 25,181 24,967
Variable Cost:
Per Year ($-000)....................................... 46,514 47,428 48,379 49,400 50,258 50,306 50,026 49,924
Per Ton ($)............................................ 6.67 6.80 6.94 7.09 7.21 7.22 7.18 7.16
Per MMBtu ($).......................................... 0.39 0.40 0.41 0.42 0.42 0.42 0.42 0.42
CORETTE STATION
Coal Purchased (Tons -- 000)............................... 810 810 810 810 810 810 810 810
Avg. Quality (Btu/Lb)...................................... 8,330 8,330 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)............................... 5.40 5.40 5.40 5.40 5.40 5.40 5.40 5.40
Transportation Cost ($/Ton).............................. 5.06 5.06 5.06 5.06 5.06 5.06 5.06 5.06
------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton........................................... 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46
Corette Total Fuel Cost* -- $-000.......................... 8,473 8,473 8,473 8,473 8,473 8,473 8,473 8,473
------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu............................... 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63
------ ------ ------ ------ ------ ------ ------ ------
2015
------
SUMMARY BY FIXED AND VARIABLE COMPONENTS
UNITS 3 & 4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000).................................... 24,796
Variable Cost:
Per Year ($-000)....................................... 49,843
Per Ton ($)............................................ 7.15
Per MMBtu ($).......................................... 0.42
CORETTE STATION
Coal Purchased (Tons -- 000)............................... 810
Avg. Quality (Btu/Lb)...................................... 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)............................... 5.40
Transportation Cost ($/Ton).............................. 5.06
------
Total -- $/Ton........................................... 10.46
Corette Total Fuel Cost* -- $-000.......................... 8,473
------
--$/MMBtu............................... 0.63
------
- ---------------
* Corette costs are considered 100% variable
Note: All dollar values are in 4th quarter 1998 dollars with no allowance for
inflation.
Note: Projections based on data from January 1999
6-14
349
TABLE 6.1 -- CONTINUED
ESTIMATED FUEL PRICE -- COLSTRIP & CORETTE STATIONS
1998 DOLLARS -- NO ALLOWANCE FOR INFLATION
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)......... 2,957 2,957 2,957 2,957 2,966 2,966 2,966 2,957 2,957 2,957
Other Sources (Tons-000)........ -- -- -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total......................... 2,957 2,957 2,957 2,957 2,966 2,966 2,966 2,957 2,957 2,957
Avg. Quality (Btu/Lb)............. 8,740 8,740 8,740 8,740 8,713 8,713 8,713 8,740 8,740 8,740
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)....... 10.82 10.30 10.59 10.35 10.32 10.72 10.89 11.23 11.10 11.61
Other Sources ($/Ton)........... -- -- -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton................ 10.82 10.30 10.59 10.35 10.32 10.72 10.89 11.23 11.10 11.61
Units 1& 2 Total Fuel Cost
-- $-000... 31,983 30,461 31,323 30,616 30,595 31,787 32,293 33,220 32,835 34,323
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
-- $/MMBtu... 0.62 0.59 0.61 0.59 0.59 0.62 0.62 0.64 0.64 0.66
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS
UNITS 1 & 2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........... 11,616 11,109 11,179 10,891 10,786 11,089 11,157 11,255 10,994 11,644
Variable Cost:
Per Year ($-000).............. 20,367 19,351 20,144 19,725 19,809 20,698 21,136 21,965 21,841 22,678
Per Ton ($)................... 6.89 6.54 6.81 6.67 6.68 6.98 7.13 7.43 7.39 7.67
Per MMBtu ($)................. 0.39 0.37 0.39 0.38 0.38 0.40 0.41 0.42 0.42 0.44
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000)......... 6,971 6,971 6,971 6,971 6,900 6,900 6,900 6,900 6,900 6,900
Other Sources (Tons-000)........ -- -- -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total......................... 6,971 6,971 6,971 6,971 6,900 6,900 6,900 6,900 6,900 6,900
Avg. Quality (Btu/Lb)............. 8,509 8,509 8,509 8,509 8,591 8,591 8,591 8,591 8,591 8,591
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton).... 9.70 9.85 9.71 9.97 8.03 8.59 8.62 9.55 9.52 9.46
Transportation Cost ($/Ton)... 0.92 0.92 0.83 0.78 0.78 0.78 0.78 0.78 0.78 0.78
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Subtotal.................... 10.62 10.77 10.54 10.75 8.81 9.37 9.40 10.33 10.31 10.24
Other Sources ($/Ton)......... -- -- -- -- -- -- -- -- -- --
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton.............. 10.62 10.77 10.54 10.75 8.81 9.37 9.40 10.33 10.31 10.24
Units 3 & 4 Total Fuel Cost
-- $-000... 74,045 75,058 73,484 74,958 60,792 64,657 64,879 71,301 71,119 70,673
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
--$/MMBtu... 0.62 0.63 0.62 0.63 0.51 0.55 0.55 0.60 0.60 0.60
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
2026 2027 2028 2029 2030 TOTAL/AVERAGE
------ ------ ------ ------ ------ -------------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)......... 2,957 2,957 2,957 2,957 2,957 93,960
Other Sources (Tons-000)........ -- -- -- -- -- --
------ ------ ------ ------ ------ ---------
Total......................... 2,957 2,957 2,957 2,957 2,957 93,960
Avg. Quality (Btu/Lb)............. 8,740 8,740 8,740 8,740 8,740 8,664
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)....... 10.98 10.83 10.86 10.69 11.10 9.70
Other Sources ($/Ton)........... -- -- -- -- -- --
------ ------ ------ ------ ------ ---------
Total -- $/Ton................ 10.98 10.83 10.86 10.69 11.10 9.70
Units 1& 2 Total Fuel Cost
-- $-000... 32,474 32,016 32,106 31,622 32,821 911,506
------ ------ ------ ------ ------ ---------
-- $/MMBtu... 0.63 0.62 0.62 0.61 0.63 0.56
------ ------ ------ ------ ------ ---------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS
UNITS 1 & 2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........... 10,389 10,054 9,791 9,427 9,281 280,287
Variable Cost:
Per Year ($-000).............. 22,085 21,962 22,315 22,196 23,540 631,219
Per Ton ($)................... 7.47 7.43 7.55 7.51 7.96 6.72
Per MMBtu ($)................. 0.43 0.42 0.43 0.43 0.46 0.39
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000)......... 6,900 6,900 6,900 6,900 6,900 218,805
Other Sources (Tons-000)........ -- -- -- -- -- --
------ ------ ------ ------ ------ ---------
Total......................... 6,900 6,900 6,900 6,900 6,900 218,805
Avg. Quality (Btu/Lb)............. 8,591 8,591 8,591 8,591 8,591 8,537
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton).... 9.86 10.00 9.89 9.62 10.38 9.52
Transportation Cost ($/Ton)... 0.78 0.78 0.78 0.77 0.77 0.91
------ ------ ------ ------ ------ ---------
Subtotal.................... 10.64 10.78 10.67 10.39 11.15 10.43
Other Sources ($/Ton)......... -- -- -- -- -- --
------ ------ ------ ------ ------ ---------
Total -- $/Ton.............. 10.64 10.78 10.67 10.39 11.15 10.43
Units 3 & 4 Total Fuel Cost
-- $-000... 73,420 74,404 73,600 71,705 76,914 2,283,196
------ ------ ------ ------ ------ ---------
--$/MMBtu... 0.62 0.63 062 0.60 0.65 0.61
------ ------ ------ ------ ------ ---------
6-15
350
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS
UNITS 3 & 4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........... 24,306 24,086 23,507 23,876 20,664 21,856 22,429 23,865 24,074 23,968
Variable Cost:
Per Year ($-000).............. 49,738 50,972 49,977 51,082 40,128 42,801 42,450 47,437 47,045 46,705
Per Ton ($)................... 7.14 7.31 7.17 7.33 5.82 6.20 6.15 6.87 6.82 6.77
Per MMBtu ($)................. 0.42 0.43 0.42 0.43 0.34 0.36 0.36 0.40 0.40 0.39
CORETTE STATION
Coal Purchased (Tons -- 000)...... 810 810 810 810 810 810 810 810 810 810
Avg. Quality (Btu/Lb)............. 8,330 8,330 8,330 8,330 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)...... 5.40 5.40 5.40 5.40 5.40 5.40 5.40 5.40 5.40 5.40
Transportation Cost ($/Ton)..... 5.06 5.06 5.06 5.06 5.06 5.06 5.06 5.06 5.06 5.06
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total -- $/Ton.................. 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46
Corette Total Fuel Cost*
-- $-000... 8,473 8,473 8,473 8,473 8,473 8,473 8,473 8,473 8,473 8,473
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
-- $/MMBtu..... 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
2026 2027 2028 2029 2030 TOTAL/AVERAGE
------ ------ ------ ------ ------ -------------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS
UNITS 3 & 4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........... 24,408 24,494 23,939 22,869 23,478 747,720
Variable Cost:
Per Year ($-000).............. 49,012 49,910 49,661 48,909 53,436 1,535,475
Per Ton ($)................... 7.10 7.23 7.20 7.07 7.74 7.02
Per MMBtu ($)................. 0.41 0.42 0.42 0.41 0.45 0.41
CORETTE STATION
Coal Purchased (Tons -- 000)...... 810 810 810 810 810 25,515
Avg. Quality (Btu/Lb)............. 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)...... 5.40 5.40 5.40 5.40 5.40 5.25
Transportation Cost ($/Ton)..... 5.06 5.06 5.06 5.06 5.06 5.06
------ ------ ------ ------ ------ ---------
Total -- $/Ton.................. 10.46 10.46 10.46 10.46 10.46 10.31
Corette Total Fuel Cost*
-- $-000... 8,473 8,473 8,473 8,473 8,473 263,100
------ ------ ------ ------ ------ ---------
-- $/MMBtu..... 0.63 0.63 0.63 0.63 0.63 0.62
------ ------ ------ ------ ------ ---------
- ---------------
* Corette costs are considered 100% variable
Note: All dollar values are in 4th quarter 1998 dollars with no allowance for
inflation.
Note: Projections based on data from January 1999
6-16
351
TABLE 6.2
ESTIMATED FUEL PRICE -- COLSTRIP & CORETTE STATIONS
INFLATED DOLLAR BASIS
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING & GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
1999 2000 2001 2002 2003
------ ------ ------ ------ ------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)......................... 1,510 3,020 3,020 3,020 3,020
Other Sources (Tons-000)........................ -- -- -- -- --
------ ------ ------ ------ ------
Total......................................... 1,510 3,020 3,020 3,020 3,020
Avg. Quality (Btu/Lb)............................. 8,558 8,558 8,558 8,558 8,558
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)....................... 8.13 8.32 8.61 8.14 8.43
Other Sources ($/Ton)........................... -- -- -- -- --
------ ------ ------ ------ ------
Total -- $/Ton................................ 8.13 8.32 8.61 8.14 8.43
Units 1& 2 Total Fuel Cost -- $-000............... 12,276 25,131 26,009 24,595 25,459
------ ------ ------ ------ ------
-- $/MMBtu................... 0.47 0.49 0.50 0.48 0.49
------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 1 &
2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)............................. 2,271 4,789 4,980 5,114 5,315
Variable Cost:
Per Year ($-000)................................ 10,005 20,342 21,029 19,482 20,145
Per Ton ($)..................................... 6.63 6.74 6.96 6.45 6.67
Per MMBtu ($)................................... 0.39 0.39 0.41 0.38 0.39
COLSTRIP UNITS 3 & 4
COAL PURCHASED:
Rosebud Mine (Tons-000)......................... 3,485 6,971 6,971 6,971 6,971
Other Sources (Tons-000)........................ -- -- -- -- --
------ ------ ------ ------ ------
Total......................................... 3,485 6,971 6,971 6,971 6,971
Avg. Quality (Btu/Lb)............................. 8,509 8,509 8,509 8,509 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton).................... 12.08 9.92 8.50 9.11 9.41
Transportation Cost ($/Ton)................... 1.63 1.65 1.29 0.94 0.96
------ ------ ------ ------ ------
Subtotal.................................... 13.71 11.57 9.80 10.04 10.37
Other Sources ($/Ton)........................... -- -- -- -- --
------ ------ ------ ------ ------
Total -- $/Ton................................ 13.71 11.57 9.80 10.04 10.37
Units 3 & 4 Total Fuel Cost -- $-000.............. 47,774 80,644 68,312 70,016 72,301
------ ------ ------ ------ ------
-- $/MMBtu................... 0.81 0.68 0.58 0.59 0.61
------ ------ ------ ------ ------
2004 2005 2006 2007 2008 2009
------ ------ ------ ------ ------ ------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)......................... 3,020 3,020 3,020 3,020 3,020 3,020
Other Sources (Tons-000)........................ -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total......................................... 3,020 3,020 3,020 3,020 3,020 3,020
Avg. Quality (Btu/Lb)............................. 8,558 8,558 8,558 8,558 8,558 8,558
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)....................... 8.68 8.94 9.25 9.92 10.22 10.54
Other Sources ($/Ton)........................... -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total -- $/Ton................................ 8.68 8.94 9.25 9.92 10.22 10.54
Units 1& 2 Total Fuel Cost -- $-000............... 26,210 27,002 27,935 29,963 30,856 31,820
------ ------ ------ ------ ------ ------
-- $/MMBtu................... 0.51 0.52 0.54 0.58 0.60 0.62
------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 1 &
2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)............................. 5,374 5,431 5,600 5,711 5,741 5,817
Variable Cost:
Per Year ($-000)................................ 20,836 21,571 22,335 24,252 25,115 26,002
Per Ton ($)..................................... 6.90 7.14 7.40 8.03 8.32 8.61
Per MMBtu ($)................................... 0.40 0.42 0.43 0.47 0.49 0.50
COLSTRIP UNITS 3 & 4
COAL PURCHASED:
Rosebud Mine (Tons-000)......................... 6,971 6,971 6,971 6,971 6,971 6,971
Other Sources (Tons-000)........................ -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total......................................... 6,971 6,971 6,971 6,971 6,971 6,971
Avg. Quality (Btu/Lb)............................. 8,509 8,509 8,509 8,509 8,509 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton).................... 10.00 10.43 10.90 11.02 11.40 11.81
Transportation Cost ($/Ton)................... 0.99 1.02 1.06 1.09 1.12 1.15
------ ------ ------ ------ ------ ------
Subtotal.................................... 11.00 11.45 11.96 12.11 12.52 12.96
Other Sources ($/Ton)........................... -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total -- $/Ton................................ 11.00 11.45 11.96 12.11 12.52 12.96
Units 3 & 4 Total Fuel Cost -- $-000.............. 76,677 79,814 83,354 84,400 87,280 90,344
------ ------ ------ ------ ------ ------
-- $/MMBtu................... 0.65 0.67 0.70 0.71 0.74 0.76
------ ------ ------ ------ ------ ------
2010 2011 2012 2013 2014 2015
------ ------ ------- ------- ------- -------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)......................... 3,020 3,020 2,957 2,957 2,957 2,957
Other Sources (Tons-000)........................ -- -- -- -- -- --
------ ------ ------- ------- ------- -------
Total......................................... 3,020 3,020 2,957 2,957 2,957 2,957
Avg. Quality (Btu/Lb)............................. 8,558 8,558 8,740 8,740 8,740 8,740
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)....................... 13.17 13.28 13.56 14.37 14.97 15.83
Other Sources ($/Ton)........................... -- -- -- -- -- --
------ ------ ------- ------- ------- -------
Total -- $/Ton................................ 13.17 13.28 13.56 14.37 14.97 15.83
Units 1& 2 Total Fuel Cost -- $-000............... 39,787 40,112 40,090 42,480 44,274 46,795
------ ------ ------- ------- ------- -------
-- $/MMBtu................... 0.77 0.78 0.78 0.82 0.86 0.91
------ ------ ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 1 &
2 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)............................. 13,497 14,321 15,051 15,902 16,367 17,187
Variable Cost:
Per Year ($-000)................................ 26,290 25,791 25,039 26,578 27,907 29,608
Per Ton ($)..................................... 8.71 8.54 8.47 8.99 9.44 10.01
Per MMBtu ($)................................... 0.51 0.50 0.48 0.51 0.54 0.57
COLSTRIP UNITS 3 & 4
COAL PURCHASED:
Rosebud Mine (Tons-000)......................... 6,971 6,971 6,971 6,971 6,971 6,971
Other Sources (Tons-000)........................ -- -- -- -- -- --
------ ------ ------- ------- ------- -------
Total......................................... 6,971 6,971 6,971 6,971 6,971 6,971
Avg. Quality (Btu/Lb)............................. 8,509 8,509 8,509 8,509 8,509 8,509
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton).................... 12.34 12.91 13.29 13.49 13.78 14.12
Transportation Cost ($/Ton)................... 1.18 1.20 1.24 1.27 1.31 1.35
------ ------ ------- ------- ------- -------
Subtotal.................................... 13.52 14.11 14.52 14.76 15.09 15.47
Other Sources ($/Ton)........................... -- -- -- -- -- --
------ ------ ------- ------- ------- -------
Total -- $/Ton................................ 13.52 14.11 14.52 14.76 15.09 15.47
Units 3 & 4 Total Fuel Cost -- $-000.............. 94,225 98,373 101,249 101,916 105,203 107,852
------ ------ ------- ------- ------- -------
-- $/MMBtu................... 0.79 0.83 0.85 0.87 0.89 0.91
------ ------ ------- ------- ------- -------
6-17
352
1999 2000 2001 2002 2003
------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 3 &
4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........................... 3,925 15,206 23,975 24,846 25,716
Variable Cost:
Per Year ($-000).............................. 43,849 65,438 44,337 45,170 46,585
Per Ton ($)................................... 12.58 9.39 6.36 6.48 6.68
Per MMBtu ($)................................. 0.74 0.55 0.37 0.38 0.39
CORETTE STATION
Coal Purchased (Tons-000)......................... 405 810 810 810 810
Avg. Quality (Btu/Lb)............................. 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)...................... 3.75 4.32 4.82 5.23 5.60
Transportation Cost ($/Ton)..................... 5.06 5.01 4.96 4.91 4.86
------ ------ ------ ------ ------
Total -- $/Ton.................................. 8.81 9.33 9.78 10.14 10.46
Corette Total Fuel Cost* -- $-000................. 3,567 7,560 7,921 8,212 8,472
-- $/MMBtu..................... 0.53 0.56 0.59 0.61 0.63
------ ------ ------ ------ ------
2004 2005 2006 2007 2008 2009
------ ------ ------ ------ ------ ------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 3 &
4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........................... 27,348 28,604 29,680 29,810 30,233 30,683
Variable Cost:
Per Year ($-000).............................. 49,329 51,210 53,674 54,590 57,047 59,661
Per Ton ($)................................... 7.08 7.35 7.70 7.83 8.18 8.56
Per MMBtu ($)................................. 0.42 0.43 0.45 0.46 0.48 0.50
CORETTE STATION
Coal Purchased (Tons-000)......................... 810 810 810 810 810 810
Avg. Quality (Btu/Lb)............................. 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)...................... 6.04 6.39 6.68 6.86 7.05 7.24
Transportation Cost ($/Ton)..................... 4.81 4.76 4.72 4.67 4.62 4.62
------ ------ ------ ------ ------ ------
Total -- $/Ton.................................. 10.85 11.15 11.40 11.53 11.67 11.86
Corette Total Fuel Cost* -- $-000................. 8,792 9,032 9,233 9,341 9,453 9,608
-- $/MMBtu..................... 0.65 0.67 0.68 0.69 0.70 0.71
------ ------ ------ ------ ------ ------
2010 2011 2012 2013 2014 2015
------ ------ ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE COMPONENTS UNITS 3 &
4 DELIVERED FUEL COST:
Fixed Cost ($/Yr-000)........................... 31,726 33,011 33,906 34,123 34,734 35,565
Variable Cost:
Per Year ($-000).............................. 62,499 65,362 67,343 68,794 70,468 72,287
Per Ton ($)................................... 8.97 9.38 9.66 9.87 10.11 10.37
Per MMBtu ($)................................. 0.53 0.55 0.57 0.58 0.59 0.61
CORETTE STATION
Coal Purchased (Tons-000)......................... 810 810 810 810 810 810
Avg. Quality (Btu/Lb)............................. 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)...................... 7.43 7.64 7.84 8.05 8.27 8.49
Transportation Cost ($/Ton)..................... 4.62 4.62 4.62 4.62 4.62 4.62
------ ------ ------- ------- ------- -------
Total -- $/Ton.................................. 12.06 12.26 12.46 12.68 12.89 13.12
Corette Total Fuel Cost* -- $-000................. 9,766 9,928 10,095 10,267 10,443 10,624
-- $/MMBtu..................... 0.72 0.74 0.75 0.76 0.77 0.79
------ ------ ------- ------- ------- -------
6-18
353
TABLE 6.2 -- CONTINUED
ESTIMATED FUEL PRICE -- COLSTRIP & CORETTE STATIONS
INFLATED DOLLAR BASIS
2016 2017 2018 2019 2020
------- ------- ------- ------- -------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)........ 2,957 2,957 2,957 2,957 2,966
Other Sources (Tons-000)....... -- -- -- -- --
------- ------- ------- ------- -------
Total........................ 2,957 2,957 2,957 2,957 2,966
Avg. Quality (Btu/Lb)............ 8,740 8,740 8,740 8,740 8,710
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)...... 16.14 15.78 16.63 16.65 17.04
Other Sources ($/Ton).......... -- -- -- -- --
------- ------- ------- ------- -------
Total -- $/Ton............... 16.14 15.78 16.63 16.65 17.04
Units 1 & 2 Total Fuel
Cost -- $-000.................. 47,730 46,659 49,169 49,238 50,544
------- ------- ------- ------- -------
--$/MMBtu... 0.92 0.90 0.95 0.95 0.98
------- ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 1 & 2 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000)............ 17,429 17,114 17,634 17,580 17,900
Variable Cost:
Per Year ($-000)............... 30,301 29,545 31,535 31,657 32,644
Per Ton ($).................... 10.25 9.99 10.66 10.71 11.01
Per MMBtu ($).................. 0.59 0.57 0.61 0.61 0.63
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000)........ 6,971 6,971 6,971 6,971 6,900
Other Sources (Tons-000)....... -- -- -- -- --
------- ------- ------- ------- -------
Total........................ 6,971 6,971 6,971 6,971 6,900
Avg. Quality (Btu/Lb)............ 8,509 8,509 8,509 8,509 8,591
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)... 14.40 15.02 15.21 16.09 13.39
Transportation Cost
($/Ton).................... 1.38 1.42 1.32 1.31 1.35
------- ------- ------- ------- -------
Subtotal................... 15.79 16.44 16.53 17.40 14.73
Other Sources ($/Ton).......... -- -- -- -- --
------- ------- ------- ------- -------
Total -- $/Ton............... 15.79 16.44 16.53 17.40 14.73
Units 3 & 4 Total Fuel
Cost -- $-000.................. 110,058 114,603 115,248 121,273 101,669
------- ------- ------- ------- -------
--$/MMBtu... 0.93 0.97 0.97 1.02 0.86
------- ------- ------- ------- -------
2021 2022 2023 2024 2025 2026
------- ------- ------- ------- ------- -------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)........ 2,966 2,966 2,957 2,957 2,957 2,957
Other Sources (Tons-000)....... -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Total........................ 2,966 2,966 2,957 2,957 2,957 2,957
Avg. Quality (Btu/Lb)............ 8,710 8,710 8,740 8,740 8,740 8,740
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)...... 18.20 18.96 20.05 20.31 21.01 21.32
Other Sources ($/Ton).......... -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Total -- $/Ton............... 18.20 18.96 20.05 20.31 21.01 21.32
Units 1 & 2 Total Fuel
Cost -- $-000.................. 53,995 56,249 59,283 60,049 62,130 63,049
------- ------- ------- ------- ------- -------
--$/MMBtu... 1.05 1.09 1.15 1.15 1.20 1.22
------- ------- ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 1 & 2 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000)............ 18,963 19,559 20,191 20,185 20,387 20,439
Variable Cost:
Per Year ($-000)............... 35,032 36,691 39,092 39,864 41,743 42,610
Per Ton ($).................... 11.81 12.37 13.22 13.48 14.12 14.41
Per MMBtu ($).................. 0.68 0.71 0.76 0.77 0.81 0.82
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000)........ 6,900 6,900 6,900 6,900 6,900 6,900
Other Sources (Tons-000)....... -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Total........................ 6,900 6,900 6,900 6,900 6,900 6,900
Avg. Quality (Btu/Lb)............ 8,591 8,591 8,591 8,591 8,591 8,591
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)... 14.76 15.19 17.23 17.55 17.87 19.08
Transportation Cost
($/Ton).................... 1.39 1.43 1.47 1.51 1.56 1.60
------- ------- ------- ------- ------- -------
Subtotal................... 16.15 16.62 18.70 19.06 19.42 20.68
Other Sources ($/Ton).......... -- -- -- -- -- --
------- ------- ------- ------- ------- -------
Total -- $/Ton............... 16.15 16.62 18.70 19.06 19.42 20.68
Units 3 & 4 Total Fuel
Cost -- $-000.................. 111,428 114,684 129,037 131,514 134,026 142,697
------- ------- ------- ------- ------- -------
--$/MMBtu... 0.94 0.97 1.09 1.11 1.13 1.20
------- ------- ------- ------- ------- -------
2027 2028 2029 2030 TOTAL/AVERAGE
------- ------- ------- ------- -------------
COLSTRIP UNITS 1 & 2
Coal Purchased:
Rosebud Mine (Tons-000)........ 2,957 2,957 2,957 2,957 93,960
Other Sources (Tons-000)....... -- -- -- -- --
------- ------- ------- ------- ---------
Total........................ 2,957 2,957 2,957 2,957 93,960
Avg. Quality (Btu/Lb)............ 8,740 8,740 8,740 8,740 8,664
Fuel Price (Delivered):
Rosebud Mine Coal ($/Ton)...... 21.64 22.30 22.56 24.06 14.97
Other Sources ($/Ton).......... -- -- -- -- --
------- ------- ------- ------- ---------
Total -- $/Ton............... 21.64 22.30 22.56 24.06 14.97
Units 1 & 2 Total Fuel
Cost -- $-000.................. 63,989 65,949 66,719 71,140 1,406,683
------- ------- ------- ------- ---------
--$/MMBtu... 1.24 1.28 1.29 1.38 0.86
------- ------- ------- ------- ---------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 1 & 2 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000)............ 20,443 20,518 20,326 20,650 437,784
Variable Cost:
Per Year ($-000)............... 43,546 45,431 46,393 50,490 968,899
Per Ton ($).................... 14.73 15.36 15.69 17.07 10.31
Per MMBtu ($).................. 0.84 0.88 0.90 0.98 0.60
COLSTRIP UNITS 3 & 4
Coal Purchased:
Rosebud Mine (Tons-000)........ 6,900 6,900 6,900 6,900 218,805
Other Sources (Tons-000)....... -- -- -- -- --
------- ------- ------- ------- ---------
Total........................ 6,900 6,900 6,900 6,900 218,805
Avg. Quality (Btu/Lb)............ 8,591 8,591 8,591 8,591 8,537
Fuel Price (Delivered):
Rosebud Mine Coal:
Coal Cost FOB Mine ($/Ton)... 19.81 20.08 20.04 22.03 14.15
Transportation Cost
($/Ton).................... 1.65 1.68 1.72 1.76 1.34
------- ------- ------- ------- ---------
Subtotal................... 21.46 21.76 21.77 23.79 15.49
Other Sources ($/Ton).......... -- -- -- -- --
------- ------- ------- ------- ---------
Total -- $/Ton............... 21.46 21.76 21.77 23.79 15.49
Units 3 & 4 Total Fuel
Cost -- $-000.................. 148,071 150,163 150,185 164,145 3,389,535
------- ------- ------- ------- ---------
--$/MMBtu... 1.25 1.27 1.27 1.38 0.91
------- ------- ------- ------- ---------
6-19
354
2016 2017 2018 2019 2020
------- ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 3 & 4 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000).......... 35,937 36,616 36,712 38,730 34,943
Variable Cost:
Per Year ($-000)............. 74,121 77,987 78,536 82,543 66,726
Per Ton ($).................. 10.63 11.19 11.27 11.84 9.67
Per MMBtu ($)................ 0.62 0.66 0.66 0.70 0.56
CORETTE STATION
Coal Purchased (Tons -- 000)..... 810 810 810 810 810
Avg. Quality (Btu/Lb)............ 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)..... 8.72 8.96 9.20 9.45 9.70
Transportation Cost ($/Ton).... 4.62 4.62 4.62 4.62 4.62
------- ------- ------- ------- -------
Total -- $/Ton................. 13.35 13.58 13.82 14.07 14.33
Corette Total Fuel
Cost* -- $-000................. 10,810 11,000 11,196 11,398 11,604
------- ------- ------- ------- -------
-- $/MMBtu....................... 0.80 0.82 0.83 0.84 0.86
------- ------- ------- ------- -------
2021 2022 2023 2024 2025 2026
------- ------- ------- ------- ------- -------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 3 & 4 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000).......... 38,245 40,203 43,749 45,211 46,129 48,235
Variable Cost:
Per Year ($-000)............. 73,183 74,480 85,287 86,303 87,897 94,462
Per Ton ($).................. 10.61 10.79 12.36 12.51 12.74 13.69
Per MMBtu ($)................ 0.62 0.63 0.72 0.73 0.74 0.80
CORETTE STATION
Coal Purchased (Tons -- 000)..... 810 810 810 810 810 810
Avg. Quality (Btu/Lb)............ 8,330 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)..... 9.97 10.23 10.51 10.80 11.09 11.39
Transportation Cost ($/Ton).... 4.62 4.62 4.62 4.62 4.62 4.62
------- ------- ------- ------- ------- -------
Total -- $/Ton................. 14.59 14.86 15.13 15.42 15.71 16.01
Corette Total Fuel
Cost* -- $-000................. 11,816 12,034 12,258 12,488 12,724 12,967
------- ------- ------- ------- ------- -------
-- $/MMBtu....................... 0.88 0.89 0.91 0.93 0.94 0.96
------- ------- ------- ------- ------- -------
2027 2028 2029 2030 TOTAL/AVERAGE
------- ------- ------- ------- -------------
SUMMARY BY FIXED AND VARIABLE
COMPONENTS UNITS 3 & 4 DELIVERED
FUEL COST:
Fixed Cost ($/Yr-000).......... 49,607 49,676 48,818 51,534 1,117,437
Variable Cost:
Per Year ($-000)............. 98,464 100,487 101,367 112,611 2,272,097
Per Ton ($).................. 14.27 14.56 14.69 16.32 10.38
Per MMBtu ($)................ 0.83 0.85 0.86 0.95 0.61
CORETTE STATION
Coal Purchased (Tons -- 000)..... 810 810 810 810 25,515
Avg. Quality (Btu/Lb)............ 8,330 8,330 8,330 8,330 8,330
Fuel Price (Delivered):
Coal Cost FOB Mine ($/Ton)..... 11.69 12.01 12.33 12.67 8.53
Transportation Cost ($/Ton).... 4.62 4.62 4.62 4.62 4.68
------- ------- ------- ------- ---------
Total -- $/Ton................. 16.32 16.63 16.96 17.29 13.21
Corette Total Fuel
Cost* -- $-000................. 13,216 13,471 13,734 14,004 337,038
------- ------- ------- ------- ---------
-- $/MMBtu....................... 0.98 1.00 1.02 1.04 0.79
------- ------- ------- ------- ---------
- ---------------
* Corette costs are considered 100% variable
Note: All dollar values are on an inflated (nominal) basis.
Note: Projections based on data from January 1999
6-20
355
APPENDIX A
MAJOR EQUIPMENT LIST
ROSEBUD MINE
ROSEBUD COUNTY, MONTANA
FOR
CHASE SECURITIES, INC.
BY
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
SEPTEMBER 1999
AVAILABILITY
YEAR OPER. HRS ----------------
EQUIP. PUT IN AGE THROUGH 1997 1998
ITEM/DESCRIPTION CAPACITY LOCATION NO. SERVICE (YRS) 1998 (%) (%)
- ---------------- ----------- -------- ------ ------- ----- --------- -------- -----
DRAGLINES:
Marion -- 8200.................................. 75 Cu Yd Area C W7000 1983 16 76,465 88.5 88.0
Marion -- 8050.................................. 60 Cu Yd Area D W5 1980 19 83,336 67.2 90.9
Marion -- 8050.................................. 60 Cu Yd Idle W46 1975 24 57,701 99.7 100.0
Marion -- 8050.................................. 60 Cu Yd Idle W47 1976 23 98,945 99.2 95.4
POWER SHOVELS:
Marion 191M..................................... 27 Cu Yd Area C W7027 1983 16 49,283 84.1 90.6
B-E 280B........................................ 17 Cu Yd Area D W41 1973 26 29,641 93.5 96.1
B-E 280B........................................ 17 Cu Yd Idle W42 1974 25 27,554 99.9 99.8
OVERBURDEN/PARTING/COAL DRILLS:
B-E Track Drill -- 60 R......................... 12 1/4" -- W48 n/a -- 13,024 98.0 93.1
Marion -- M3.................................... 12 1/4" Area C W7034 1984 15 24,623 85.6 97.5
Ingersol Rand -- DM45E.......................... 9 7/8" -- W415 n/a -- 16,250 98.8 88.9
Gardner Denver -- RDC16......................... 4 1/4" Area D W422 1989 10 10,610 n/a 100.0
Gardner Denver -- RDC16......................... 4 1/4" Area C W7055 1985 14 13,454 n/a 100.0
FRONT-END LOADERS:
Caterpillar -- 992C............................. 16 Cu Yd Area D W416 1989 10 29,422 79.1 82.1
Caterpillar -- 992D............................. 16 Cu Yd Area C W7074 1992 7 20,306 90.3 93.9
Caterpillar -- 992C............................. 15 Cu Yd Area C W15 1981 18 42,222 86.4 77.3
Caterpillar -- 970F............................. 8.75 Cu Yd -- 716 1998 1 1,980 New 1998 99.1
Komatsu -- WA6001L.............................. 8 Cu Yd Area D W458 1994 5 24,102 79.8 90.9
Caterpillar -- IT28............................. 2.25 Cu Yd Conv. W9016 n/a -- 9,992 n/a n/a
John Deere Loader/BH............................ 1 Cu Yd Conv. W9006 1983 16 6,145 n/a n/a
BOTTOM DUMP COAL HAULERS:
Dart -- 4160.................................... 160 Ton Area C W7028 1983 16 49,250 88.0 82.7
Dart -- 4160.................................... 160 Ton Area C W7029 1983 16 53,467 81.4 83.6
Dart -- 4160.................................... 160 Ton Area C W7030 1984 15 51,547 79.1 85.2
Dart -- 4160.................................... 160 Ton Area C W7031 1984 15 51,612 83.1 80.4
Caterpillar 776B................................ 160 Ton Area C W7061 1988 11 39,460 79.0 63.5
Euclid -- CH120................................. 120 Ton Area D W34 1974 25 72,663 80.8 72.6
Euclid -- CH120................................. 120 Ton Area D W35 1974 25 68,820 80.3 91.4
Euclid -- CH120................................. 120 Ton Area D W36 1975 24 74,292 76.5 71.5
Euclid -- CH120................................. 120 Ton Area D W37 1975 24 80,864 84.2 75.3
Euclid -- CH120................................. 120 Ton Area D W38 1975 24 70,675 77.0 74.3
Euclid -- CH120................................. 120 Ton Area D W66 1976 23 83,427 72.0 80.4
Euclid -- CH120................................. 120 Ton Area D W67 1976 23 71,905 90.2 70.1
A-1
356
AVAILABILITY
YEAR OPER. HRS ----------------
EQUIP. PUT IN AGE THROUGH 1997 1998
ITEM/DESCRIPTION CAPACITY LOCATION NO. SERVICE (YRS) 1998 (%) (%)
- ---------------- ----------- -------- ------ ------- ----- --------- -------- -----
END DUMP TRUCK:
Euclid -- R35................................... 35 Ton Area D W264 1983 16 23,552 n/a n/a
WATER TRUCKS:
Caterpillar -- 631D............................. 10000 Gal. Area D W258 1983 16 26,601 89.6 76.1
Caterpillar -- 631D............................. 10000 Gal. Idle W259 n/a -- 32,932 72.6 82.6
Caterpillar -- 631D............................. 10000 Gal. Area D W455 1983 16 26,096 77.4 68.8
Caterpillar -- 631D............................. 10000 Gal. Area C W7003 1983 16 27,403 83.6 83.5
Caterpillar -- 631D............................. 10000 Gal. -- W7011 n/a -- 41,004 89.3 93.5
Caterpillar -- 631D............................. 10000 Gal. Area C W7046 1983 16 41,234 96.3 66.4
TRACK DOZERS:
Caterpillar -- D11N............................. 53 Cu Yd Area C W424 1989 10 44,163 75.5 71.5
Caterpillar -- D11R............................. 45 Cu Yd Area D 630 1997 2 12,363 91.6 86.2
Komatsu -- D475A2............................... 45 Cu Yd Area C W7073 1992 7 31,828 83.0 66.9
Caterpillar -- D10N............................. 28 Cu Yd Area D W412 1988 11 39,983 71.2 81.2
Komatsu -- D375A3............................... 28 Cu Yd Area D 701 1997 2 5,332 79.9 83.8
Caterpillar -- D10R............................. 28 Cu Yd Area C 615 1996 3 15,170 81.9 76.4
Komatsu -- D375A................................ 26 Cu Yd -- W467 n/a -- 33,657 80.8 76.5
Caterpillar -- D9N.............................. 17 Cu Yd Area C W7075 1994 5 20,014 92.6 95.0
GRADERS:
Caterpillar -- 14G.............................. 18 ft. Area C W7026 1984 15 38,202 91.3 85.0
Caterpillar -- 16G.............................. 16 ft. Area C W423 1989 10 40,449 74.6 82.5
Caterpillar -- 16H.............................. 16 ft. Area D 616 1996 3 10,483 93.7 90.7
Caterpillar -- 16H.............................. 16 ft. Area C 727 1998 1 3,073 New 1998 94.3
Caterpillar -- 130G............................. 14 ft. Area D W7068 1984 15 12,222 99.5 91.0
SCRAPERS:
Caterpillar -- 657E............................. 35 Cu Yd Area C 610 1996 3 13,689 91.9 94.5
Caterpillar -- 657E............................. 35 Cu Yd Area D 611 1996 3 13,087 90.6 94.4
BACKHOE:
Caterpillar -- 245.............................. 3 - 5 Cu Yd Area D W207 1981 18 22,789 73.1 94.3
- ---------------
Note: n/a indicates not available.
A-2
357
[LOGO]
358
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 10.1 of PPL Montana's Limited Liability Company Agreement provides
that PPL Montana will indemnify its member, managers, officers and certain other
persons to the extent permitted by law.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*1.1 Purchase Agreement dated July 13, 2000 between the Company
and Chase Securities Inc., Credit Suisse First Boston
Corporation, UBS Warburg LLC and TD Securities (USA) Inc.
*3.1 Certificate of Formation of PPL Montana, LLC, dated December
23, 1998, as amended.
*3.2 Limited Liability Company Agreement and By-Laws of PPL
Montana, LLC, effective as of December 17, 1999.
*4.1 Exchange and Registration Rights Agreement dated July 13,
2000 among the Company and Chase Securities Inc., Credit
Suisse First Boston Corporation, UBS Warburg LLC and TD
Securities (USA) Inc.
*4.2 Pass Through Trust Agreement dated July 20, 2000 with
respect to the formation of the Colstrip 2000 Pass Through
Trust, between the Company and The Chase Manhattan Bank, as
Pass Through Trustee.
*4.3 Letter of Representations dated July 19, 2000, among the
Company, The Chase Manhattan Bank and The Depository Trust
Company.
*4.4 Form of 8.903% Pass Through Certificate.
*4.5a Participation Agreement (BA 1/2) dated July 13, 2000 among
the Company, Montana OL3 LLC, Wilmington Trust Company,
Montana OP3 LLC, and The Chase Manhattan Bank, as Lease
Indenture Trustee and as Pass Through Trustee.
*4.5b Schedule identifying substantially identical agreement to
Participation Agreement constituting Exhibit 4.5a hereto.
*4.6a Participation Agreement (BA 3) dated July 13, 2000 among the
Company, Montana OL4 LLC, Wilmington Trust Company, Montana
OP4 LLC, and The Chase Manhattan Bank, as Lease Indenture
Trustee and as Pass Through Trustee.
*4.6b Schedule identifying substantially identical agreement to
Participation Agreement constituting Exhibit 4.6a hereto.
*4.7a Facility Lease Agreement (BA 1/2), between the Company and
Montana OL3 LLC.
*4.7b Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.7a hereto.
*4.8a Facility Lease Agreement (BA 3), between the Company and
Montana OL4 LLC.
*4.8b Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.8a hereto.
*4.9a Indenture of Trust, Mortgage and Security Agreement (BA
1/2), between Montana OL3 LLC and The Chase Manhattan Bank.
*4.9b Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement
constituting Exhibit 4.9a hereto.
*4.10a Indenture of Trust, Mortgage and Security Agreement (BA 3),
between Montana OL4 LLC and The Chase Manhattan Bank.
II-1
359
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*4.10b Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement
constituting Exhibit 4.10a hereto.
*5.1 Opinion of Orrick, Herrington & Sutcliffe LLP as to the
legality of the Pass Through Certificates being registered
hereby.
8.1 Opinion of Orrick, Herrington & Sutcliffe LLP regarding tax
matters.
*10.1a Asset Purchase Agreement dated as of October 31, 1998 by and
between PP&L Global, Inc. and The Montana Power Company
(incorporated by reference to The Montana Power Company's
Form 8-K, as filed with the Commission on November 9, 1998,
File No. 001-04566).
*10.1b Amendment No. 1 dated as of June 29, 1999 to the Asset
Purchase Agreement dated as of October 31, 1998 by and
between PP&L Global, Inc. and The Montana Power Company.
*10.1c Amendment No. 2 dated as of October 29, 1999 to the Asset
Purchase Agreement dated as of October 31, 1998 by and
between PPL Global, Inc. and The Montana Power Company.
*10.2 Instrument of Assignment dated as of December 17, 1999 among
PPL Global, the Company and Colstrip Comm Serv, LLC.
*10.3 Construction and Ownership Agreement dated July 30, 1971,
pertaining to Colstrip Units 1 and 2, as amended October 21,
1998, between The Montana Power Company and Puget Sound
Power & Light Company.
*10.4 Agreement for the Operation and Maintenance of Colstrip
Steam Electric Generating Plant dated July 30, 1971,
pertaining to Colstrip Units 1 and 2, between The Montana
Power Company and Puget Sound Power & Light Company.
*10.5a Ownership & Operation Agreement Colstrip Units 3 & 4 dated
as of May 6, 1981, among The Montana Power Company, First
Trust Company of Montana, Puget Sound Power and Light
Company, Puget Colstrip Construction Company, The Washington
Water Power Company, Portland General Electric Company and
Pacific Power & Light Company.
*10.5b Amendment No. 1 to the Ownership & Operation Agreement dated
as of October 11, 1991, pertaining to Colstrip Units 3 & 4,
among The Montana Power Company, Puget Sound Power and Light
Company, The Washington Water Power Company, Portland
General Electric Company and PacifiCorp (doing business as
Pacific Power & Light Company).
*10.5c Amendment No. 2 to the Ownership & Operation Agreement dated
as of July 13, 1998, pertaining to Colstrip Units 3 & 4,
among The Montana Power Company, Puget Sound Power and Light
Company (now Puget Sound Energy, Inc.), The Washington Water
Power Company, Portland General Electric Company and Pacific
Power & Light Company (now PacifiCorp).
*10.6a Common Facilities Agreement Colstrip Units #1, #2, #3 and #4
dated as of May 6, 1981, as amended January 21, 1992, among
The Montana Power Company, Puget Sound Power & Light
Company, Puget Colstrip Construction Company, Portland
General Electric Company, The Washington Water Power Company
and Pacific Power & Light Company (now PacifiCorp).
*10.6b Amendment No. 1 to the Common Facilities Agreement dated as
of January 21, 1992, among The Montana Power Company, Puget
Sound Power and Light Company, Portland General Electric
Company, The Washington Water Power Company and PacifiCorp
(doing business as Pacific Power and Light Company).
*10.7 MPC/PP&L Colstrip Units 3 & 4 Generating Project Reciprocal
Sharing Agreement dated as of December 15, 1999 by and
between The Montana Power Company and the Company.
*10.8 Credit Agreement dated as of November 16, 1999 among the
Company, the Lenders party thereto (as defined therein) and
The Chase Manhattan Bank.
*10.9 General Assignment and Bill of Sale between The Montana
Power Company and the Company, dated December 17, 1999.
II-2
360
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*10.10 Assignment and Assumption Agreement (Colstrip 1 and 2
Agreements) dated as of December 17, 1999 by and between The
Montana Power Company and the Company.
*10.11 Assignment and Assumption Agreement (Colstrip 3 and 4
Agreements) dated as of December 17, 1999 by and between The
Montana Power Company and the Company.
*10.12 Project Committee Vote Sharing Agreement dated as of
December 15, 1999, between The Montana Power Company and the
Company.
*10.13 Colstrip Unit Number 3 Wholesale Transition Service
Agreement dated as of December 17, 1999, by and between the
Company and The Montana Power Company.
*10.14 Non Colstrip Unit Number 3 Wholesale Transition Service
Agreement dated as of December 17, 1999 by and between the
Company and The Montana Power Company.
*10.15 Equity Contribution Agreement dated July 20, 2000 between
PPL Corporation and the Company.
*10.16a Bill of Sale (BA 1/2), between the Company and Montana OL3
LLC.
*10.16b Schedule identifying substantially identical agreement to
Bill of Sale constituting Exhibit 10.17a hereto.
*10.17a Site Lease and Sublease (BA 1/2), between the Company and
Montana OL3 LLC.
*10.17b Schedule identifying substantially identical agreement to
Site Lease and Sublease constituting Exhibit 10.19a hereto.
*10.18a Assignment and Reassignment of Project Agreements (BA 1/2),
between the Company and Montana OL3 LLC.
*10.18b Schedule identifying substantially identical agreement to
Assignment and Reassignment of Project Agreements
constituting Exhibit 10.20a hereto.
*10.19 Omnibus Voting Rights Agreement (BA/NC-1/2), among the
Company, Montana OL1 LLC, Montana OL3 LLC, and the Lease
Indenture Trustee.
*10.20a Bill of Sale (BA 3), between the Company and Montana OL4
LLC.
*10.20b Schedule identifying substantially identical agreement to
Bill of Sale constituting Exhibit 10.23a hereto.
*10.21a Site Lease and Sublease (BA 3), between the Company and
Montana OL4 LLC.
*10.21b Schedule identifying substantially identical agreement to
Site Lease and Sublease constituting Exhibit 10.25a hereto.
*10.22a Assignment and Reassignment of Project Agreements (BA 3),
between the Company and Montana OL4 LLC.
*10.22b Schedule identifying substantially identical agreement to
Assignment and Reassignment of Project Agreements
constituting Exhibit 10.26a hereto.
*10.23 Omnibus Voting Rights Agreement (BA/NC-3), among the
Company, Montana OL1 LLC, Montana OL4 LLC, and the Lease
Indenture Trustee.
*10.24 Brokering and Contract Management Agreement, dated as of
December 17, 1999, between PP&L EnergyPlus Co., LLC and the
Company.
*10.25 Memorandum of Understanding, dated as of June 26, 2000,
between PPL EnergyPlus, LLC and the Company.
*12.1 Statement regarding ratio of earnings to fixed charges.
*23.1 Consent of Winthrop, Stimson, Putnam and Roberts.
*23.2 Consent of Orrick, Herrington & Sutcliffe LLP (included in
Exhibits 5.1 and 8.1 to this Registration Statement).
23.3 Consent of PricewaterhouseCoopers LLP.
*23.4 Consent of R.W. Beck, Inc.
II-3
361
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*23.5 Consent of PA Consulting Services Inc.
*23.6 Consent of John T. Boyd Company.
*24.1 Power-of-Attorney (contained on the signature page of this
Registration Statement).
*25.1 Statement of Eligibility and Qualification on Form T-1 of
The Chase Manhattan Bank.
*27.1 Financial Data Schedule.
*99.1 Form of Letter of Transmittal.
*99.2 Form of Letter to Clients.
*99.3 Form of Letter to Brokers, Dealers, Commercial Banks, Trust
Companies and Other Nominees.
*99.4 Form of Notice of Guaranteed Delivery.
- ---------------
* previously filed
(b) Financial Statement Schedules
Financial statement schedules are not included as the required information
is inapplicable or is presented in the financial statements or the notes
thereto.
ITEM 22. UNDERTAKINGS
(a) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant, pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the SEC such indemnification
is against public policy as expressed in the Securities Act of 1933 and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by any such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question of whether or not such indemnification is against
public policy as expressed in the Securities Act of 1933 and will be governed by
the final adjudication of such issue.
(b) The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of such
request, and to send the incorporated documents by first class mail or other
equally prompt means. This includes information contained in documents filed
subsequent to the effective date of the registration statement through the date
of responding to the request.
(c) The undersigned registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
(d) The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by section 10(a)(3) of
the Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising
after the effective date of the registration statement (or
the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental
change in the information set forth in the registration
statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or
high end
II-4
362
of the estimated maximum offering range may be reflected in the
form of prospectus filed with the Commission pursuant to Rule
424(b) (sec.230.424(b) of this chapter) if, in the aggregate, the
changes in volume and price represent no more than a 20% change
in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the effective
registration statement.
(iii) To include any material information with respect to the
plan of distribution not previously disclosed in the
registration statement or any material change to such
information in the registration statement;
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
(4) If the registrant is a foreign private issuer, to file a
post-effective amendment to the registration statement to include any
financial statements required by Item 8.A of Form 20-F at the start of any
delayed offering or throughout a continuous offering. Financial statements
and information otherwise required by Section 10(a)(3) of the Act need not
be furnished, provided that the registrant includes in the prospectus, by
means of a post-effective amendment, financial statements required pursuant
to this paragraph (a)(4) and other information necessary to ensure that all
other information in the prospectus is at least as current as the date of
those financial statements. Notwithstanding the foregoing, with respect to
registration statements on Form F-3, a post-effective amendment need not be
filed to include financial statements and information required by Section
10(a)(3) of the Act or sec.210.3-19 of this chapter if such financial
statements and information are contained in periodic reports filed with or
furnished to the Commission by the registrant pursuant to section 13 or
section 15(d) of the Securities Exchange Act of 1934 that are incorporated
by reference in the Form F-3.
II-5
363
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this amendment no. 3 to the registration statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Billings, State of Montana on the 1st day of March, 2001.
PPL MONTANA, LLC
a Delaware limited liability company
By: /s/ PAUL A. FARR
------------------------------------
Paul A. Farr
Vice President
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature
appears below hereby constitutes and appoints Paul A. Farr and David B. Kinnard,
or either of them, as his true and lawful attorneys and agents, to do any and
all acts and things in his name and on his behalf in any and all capacities,
including as an individual or as an officer or director authorized to act on
behalf of an entity, and to execute any and all instruments for him and in his
name in the capacity indicated below, which said attorneys and agents, or either
of them, may deem necessary or advisable to enable PPL Montana, LLC to comply
with the Securities Act and any rules, regulations and requirements of the SEC
in connection with this registration statement, including specifically, but
without limitation, power and authority to sign for him in his name in the
capacity indicated below, any and all amendments (including post-effective
amendments) hereto; and each such person does hereby ratify and confirm all that
said attorneys and agents, or either of them, shall do or cause to be done by
virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this amendment
no. 3 to the registration statement has been signed by the following persons in
the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
* President, Chief Executive Officer
- --------------------------------------------------- and Manager (Principal executive
Roger L. Petersen officer)
/s/ PAUL A. FARR Vice President, Chief Financial March 1, 2001
- --------------------------------------------------- Officer and Assistant Secretary
Paul A. Farr (Principal financial and
accounting officer)
* Vice President, General Counsel
- --------------------------------------------------- and Secretary
David B. Kinnard
* Manager
- ---------------------------------------------------
John R. Biggar
* Manager
- ---------------------------------------------------
Paul T. Champagne
II-6
364
SIGNATURE TITLE DATE
--------- ----- ----
* Manager
- ---------------------------------------------------
Robert J. Grey
* Manager
- ---------------------------------------------------
William F. Hecht
* Manager
- ---------------------------------------------------
Frank A. Long
* By: /s/ PAUL A. FARR March 1, 2001
------------------------------------------
Name: Paul A. Farr
Attorney-in fact
II-7
365
EXHIBIT INDEX
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- ----------- ------
*1.1 Purchase Agreement dated July 13, 2000 between the Company
and Chase Securities Inc., Credit Suisse First Boston
Corporation, UBS Warburg LLC and TD Securities (USA)
Inc. .......................................................
*3.1 Certificate of Formation of PPL Montana, LLC, dated December
23, 1998, as amended........................................
*3.2 Limited Liability Company Agreement and By-Laws of PPL
Montana, LLC, effective as of December 17, 1999.............
*4.1 Exchange and Registration Rights Agreement dated July 13,
2000 among the Company and Chase Securities Inc., Credit
Suisse First Boston Corporation, UBS Warburg LLC and TD
Securities (USA) Inc. ......................................
*4.2 Pass Through Trust Agreement dated July 20, 2000 with
respect to the formation of the Colstrip 2000 Pass Through
Trust, between the Company and The Chase Manhattan Bank, as
Pass Through Trustee........................................
*4.3 Letter of Representations dated July 19, 2000, among the
Company, The Chase Manhattan Bank and The Depository Trust
Company.....................................................
*4.4 Form of 8.903% Pass Through Certificate.....................
*4.5a Participation Agreement (BA 1/2) dated July 13, 2000 among
the Company, Montana OL3 LLC, Wilmington Trust Company,
Montana OP3 LLC, and The Chase Manhattan Bank, as Lease
Indenture Trustee and as Pass Through Trustee...............
*4.5b Schedule identifying substantially identical agreement to
Participation Agreement constituting Exhibit 4.5a hereto....
*4.6a Participation Agreement (BA 3) dated July 13, 2000 among the
Company, Montana OL4 LLC, Wilmington Trust Company, Montana
OP4 LLC, and The Chase Manhattan Bank, as Lease Indenture
Trustee and as Pass Through Trustee.........................
*4.6b Schedule identifying substantially identical agreement to
Participation Agreement constituting Exhibit 4.6a hereto....
*4.7a Facility Lease Agreement (BA 1/2), between the Company and
Montana OL3 LLC.............................................
*4.7b Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.7a hereto...
*4.8a Facility Lease Agreement (BA 3), between the Company and
Montana OL4 LLC.............................................
*4.8b Schedule identifying substantially identical agreement to
Facility Lease Agreement constituting Exhibit 4.8a hereto...
*4.9a Indenture of Trust, Mortgage and Security Agreement (BA
1/2), between Montana OL3 LLC and The Chase Manhattan
Bank........................................................
*4.9b Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement
constituting Exhibit 4.9a hereto............................
*4.10a Indenture of Trust, Mortgage and Security Agreement (BA 3),
between Montana OL4 LLC and The Chase Manhattan Bank........
*4.10b Schedule identifying substantially identical agreement to
Indenture of Trust, Mortgage and Security Agreement
constituting Exhibit 4.10a hereto...........................
*5.1 Opinion of Orrick, Herrington & Sutcliffe LLP as to the
legality of the Pass Through Certificates being registered
hereby......................................................
8.1 Opinion of Orrick, Herrington & Sutcliffe LLP regarding tax
matters.....................................................
*10.1a Asset Purchase Agreement dated as of October 31, 1998 by and
between PP&L Global, Inc. and The Montana Power Company
(incorporated by reference to The Montana Power Company's
Form 8-K, as filed with the Commission on November 9, 1998,
File No. 001-04566).........................................
366
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- ----------- ------
*10.1b Amendment No. 1 dated as of June 29, 1999 to the Asset
Purchase Agreement dated as of October 31, 1998 by and
between PP&L Global, Inc. and The Montana Power Company.....
*10.1c Amendment No. 2 dated as of October 29, 1999 to the Asset
Purchase Agreement dated as of October 31, 1998 by and
between PPL Global, Inc. and The Montana Power Company......
*10.2 Instrument of Assignment dated as of December 17, 1999 among
PPL Global, the Company and Colstrip Comm Serv, LLC.........
*10.3 Construction and Ownership Agreement dated July 30, 1971,
pertaining to Colstrip Units 1 and 2, as amended October 21,
1998, between The Montana Power Company and Puget Sound
Power & Light Company.......................................
*10.4 Agreement for the Operation and Maintenance of Colstrip
Steam Electric Generating Plant dated July 30, 1971,
pertaining to Colstrip Units 1 and 2, between The Montana
Power Company and Puget Sound Power & Light Company.........
*10.5a Ownership & Operation Agreement Colstrip Units 3 & 4 dated
as of May 6, 1981, among The Montana Power Company, First
Trust Company of Montana, Puget Sound Power and Light
Company, Puget Colstrip Construction Company, The Washington
Water Power Company, Portland General Electric Company and
Pacific Power & Light Company...............................
*10.5b Amendment No. 1 to the Ownership & Operation Agreement dated
as of October 11, 1991, pertaining to Colstrip Units 3 & 4,
among The Montana Power Company, Puget Sound Power and Light
Company, The Washington Water Power Company, Portland
General Electric Company and PacifiCorp (doing business as
Pacific Power & Light Company)..............................
*10.5c Amendment No. 2 to the Ownership & Operation Agreement dated
as of July 13, 1998, pertaining to Colstrip Units 3 & 4,
among The Montana Power Company, Puget Sound Power and Light
Company (now Puget Sound Energy, Inc.), The Washington Water
Power Company, Portland General Electric Company and Pacific
Power & Light Company (now PacifiCorp)......................
*10.6a Common Facilities Agreement Colstrip Units #1, #2, #3 and #4
dated as of May 6, 1981, as amended January 21, 1992, among
The Montana Power Company, Puget Sound Power & Light
Company, Puget Colstrip Construction Company, Portland
General Electric Company, The Washington Water Power Company
and Pacific Power & Light Company (now PacifiCorp)..........
*10.6b Amendment No. 1 to the Common Facilities Agreement dated as
of January 21, 1992, among The Montana Power Company, Puget
Sound Power and Light Company, Portland General Electric
Company, The Washington Water Power Company and PacifiCorp
(doing business as Pacific Power and Light Company).........
*10.7 MPC/PP&L Colstrip Units 3 & 4 Generating Project Reciprocal
Sharing Agreement dated as of December 15, 1999 by and
between The Montana Power Company and the Company...........
*10.8 Credit Agreement dated as of November 16, 1999 among the
Company, the Lenders party thereto (as defined therein) and
The Chase Manhattan Bank....................................
*10.9 General Assignment and Bill of Sale between The Montana
Power Company and the Company, dated December 17, 1999......
*10.10 Assignment and Assumption Agreement (Colstrip 1 and 2
Agreements) dated as of December 17, 1999 by and between The
Montana Power Company
and the Company.............................................
*10.11 Assignment and Assumption Agreement (Colstrip 3 and 4
Agreements) dated as of December 17, 1999 by and between The
Montana Power Company
and the Company.............................................
367
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- ----------- ------
*10.12 Project Committee Vote Sharing Agreement dated as of
December 15, 1999, between The Montana Power Company and the
Company.....................................................
*10.13 Colstrip Unit Number 3 Wholesale Transition Service
Agreement dated as of December 17, 1999, by and between the
Company and The Montana Power Company.......................
*10.14 Non Colstrip Unit Number 3 Wholesale Transition Service
Agreement dated as of December 17, 1999 by and between the
Company and The Montana Power Company.......................
*10.15 Equity Contribution Agreement dated July 20, 2000 between
PPL Corporation and the Company.............................
*10.16a Bill of Sale (BA 1/2), between the Company and Montana OL3
LLC.........................................................
*10.16b Schedule identifying substantially identical agreement to
Bill of Sale constituting Exhibit 10.17a hereto.............
*10.17a Site Lease and Sublease (BA 1/2), between the Company and
Montana OL3 LLC.............................................
*10.17b Schedule identifying substantially identical agreement to
Site Lease and Sublease constituting Exhibit 10.19a
hereto......................................................
*10.18a Assignment and Reassignment of Project Agreements (BA 1/2),
between the Company and Montana OL3 LLC.....................
*10.18b Schedule identifying substantially identical agreement to
Assignment and Reassignment of Project Agreements
constituting Exhibit 10.20a hereto..........................
*10.19 Omnibus Voting Rights Agreement (BA/NC-1/2), among the
Company, Montana OL1 LLC, Montana OL3 LLC, and the Lease
Indenture Trustee...........................................
*10.20a Bill of Sale (BA 3), between the Company and Montana OL4
LLC.........................................................
*10.20b Schedule identifying substantially identical agreement to
Bill of Sale constituting Exhibit 10.23a hereto.............
*10.21a Site Lease and Sublease (BA 3), between the Company and
Montana OL4 LLC.............................................
*10.21b Schedule identifying substantially identical agreement to
Site Lease and Sublease constituting Exhibit 10.25a
hereto......................................................
*10.22a Assignment and Reassignment of Project Agreements (BA 3),
between the Company and Montana OL4 LLC.....................
*10.22b Schedule identifying substantially identical agreement to
Assignment and Reassignment of Project Agreements
constituting Exhibit 10.26a hereto..........................
*10.23 Omnibus Voting Rights Agreement (BA/NC-3), among the
Company, Montana OL1 LLC, Montana OL4 LLC, and the Lease
Indenture Trustee...........................................
*10.24 Brokering and Contract Management Agreement, dated as of
December 17, 1999, between PP&L EnergyPlus Co., LLC and the
Company.....................................................
*10.25 Memorandum of Understanding, dated as of June 26, 2000,
between PPL EnergyPlus, LLC and the Company.................
*12.1 Statement regarding ratio of earnings to fixed charges......
*23.1 Consent of Winthrop, Stimson, Putnam and Roberts............
*23.2 Consent of Orrick, Herrington & Sutcliffe LLP (included in
Exhibits 5.1 and 8.1 to this Registration Statement)........
23.3 Consent of PricewaterhouseCoopers LLP.......................
*23.4 Consent of R.W. Beck, Inc...................................
*23.5 Consent of PA Consulting Services Inc.......................
*23.6 Consent of John T. Boyd Company.............................
*24.1 Power-of-Attorney (contained on the signature page of this
Registration Statement).....................................
*25.1 Statement of Eligibility and Qualification on Form T-1 of
The Chase Manhattan Bank....................................
*27.1 Financial Data Schedule.....................................
368
EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
- ------- ----------- ------
*99.1 Form of Letter of Transmittal...............................
*99.2 Form of Letter to Clients...................................
*99.3 Form of Letter to Brokers, Dealers, Commercial Banks, Trust
Companies and Other Nominees................................
*99.4 Form of Notice of Guaranteed Delivery.......................
- ---------------
* previously filed