AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 7, 2001
REGISTRATION NO. 333-
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
-----------------
PPL ENERGY SUPPLY, LLC
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 23-3074920
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
TWO NORTH NINTH STREET
ALLENTOWN, PENNSYLVANIA 18101-1179
(610) 774-5151
(Address, including zip code, and telephone number, including area code,
of registrant's principal executive offices)
JAMES E. ABEL, TREASURER
PPL ENERGY SUPPLY, LLC
TWO NORTH NINTH STREET
ALLENTOWN, PENNSYLVANIA 18101-1179
(610) 774-5151
(NAME AND ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA
CODE, OF AGENT FOR SERVICE)
-----------------
COPIES TO:
CATHERINE C. HOOD
THELEN REID & PRIEST LLP
40 WEST 57/TH/ STREET
NEW YORK, NEW YORK 10019
(212) 603-2000
-----------------
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. [ ]
-----------------
CALCULATION OF REGISTRATION FEE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PROPOSED PROPOSED
MAXIMUM MAXIMUM
AMOUNT TO BE OFFERING PRICE PER AGGREGATE AMOUNT OF
TITLE OF EACH CLASS OF SECURITIES TO BE REGISTERED REGISTERED UNIT (1) OFFERING PRICE (1) REGISTRATION FEE
- -------------------------------------------------- ------------ ------------------ ------------------ ----------------
Senior Notes, 6.40% Exchange Series A due
2011........................................ $500,000,000 100% $500,000,000 $119,500
- -------------------------------------------------- ------------ ------------------ ------------------ ----------------
- --------------------------------------------------------------------------------
(1)Determined solely for the purpose of calculating the registration fee
pursuant to Rule 457(f)(2) promulgated under the Securities Act.
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, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE
ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID
SECTION 8(A), MAY DETERMINE.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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 JURISDICTION IN WHICH THE OFFER OR SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION DATED DECEMBER 7, 2001
PRELIMINARY PROSPECTUS
[Graphic]
$500,000,000
PPL ENERGY SUPPLY, LLC
OFFER TO EXCHANGE
SENIOR NOTES, 6.40% EXCHANGE SERIES A DUE 2011
(WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT)
FOR ANY AND ALL OUTSTANDING
SENIOR NOTES, 6.40% SERIES A DUE 2011
(WHICH HAVE NOT BEEN SO REGISTERED)
THIS EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M.
NEW YORK CITY TIME, , 2002 UNLESS EXTENDED
TERMS OF THE EXCHANGE OFFER
. The terms of the new notes are substantially identical to the terms of the
old notes, except that the new notes are registered under the Securities Act
and the transfer restrictions and registration rights and related additional
interest provisions applicable to the old notes do not apply to the new
notes.
. We will accept all old notes that noteholders properly tender and do not
withdraw before the expiration of the exchange offer.
. Tenders of original notes may be withdrawn at any time prior to expiration
of the exchange offer.
. You will not recognize any income, gain or loss for U.S. federal income tax
purposes as a result of the exchange.
. Like the old notes, the new notes will be unsecured.
. The exchange offer is not conditioned on the tender of any minimum principal
amount of old notes.
. We do not intend to apply for listing of the new notes on any securities
exchange or to arrange for them to be quoted on any automated quotation
system.
Each broker-dealer that receives new notes for its own account pursuant to
the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of such new notes. The letter of transmittal states
that by so acknowledging 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. 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 notes
received in exchange for old notes where such old notes were acquired by such
broker-dealer as a result of market-making activities or other trading
activities. We have agreed that, for a period of 180 days after the
consummation of the registered exchange offer, we will make this prospectus
available to any broker-dealer for use in connection with any such resale. See
"Plan of Distribution."
-----------------
SEE "RISK FACTORS" BEGINNING ON PAGE 15 FOR A DISCUSSION OF FACTORS YOU
SHOULD CONSIDER IN CONNECTION WITH THIS EXCHANGE OFFER.
-----------------
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities, or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The date of this prospectus is , 2002.
-----------------
TABLE OF CONTENTS
PAGE
----
Where You Can Find More Information......... i
Summary..................................... 1
Risk Factors................................ 15
Forward-Looking Information................. 27
Use of Proceeds............................. 28
Capitalization.............................. 28
Selected Financial Information and Operating
Data...................................... 29
Management's Discussion and Analysis of
Financial Condition And Results of
Operations................................ 31
Business.................................... 47
Management.................................. 82
Certain Relationships and Related
Transactions.............................. 85
PAGE
----
The Exchange Offer............. 87
Description of the New Notes... 95
Certain U.S. Federal Income Tax
Considerations............... 110
Plan of Distribution........... 114
Experts........................ 115
Validity of the New Notes...... 115
Index to Financial Statements.. F-1
Annex A--Summary Independent
Technical Review............. A-1
Annex B--Independent Market
Consultant's Report.......... B-1
-----------------
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS OR TO
WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
INFORMATION THAT IS DIFFERENT. THE INFORMATION IN THIS PROSPECTUS MAY ONLY BE
ACCURATE ON THE DATE OF THIS PROSPECTUS. THE BUSINESS PROFILE, FINANCIAL
CONDITION, RESULTS OF OPERATIONS AND PROSPECTS OF PPL ENERGY SUPPLY MAY HAVE
CHANGED SINCE THAT DATE. THIS PROSPECTUS IS AN OFFER TO EXCHANGE ONLY THE NOTES
OFFERED BY THIS PROSPECTUS, BUT ONLY UNDER CIRCUMSTANCES AND IN JURISDICTIONS
WHERE IT IS LAWFUL TO DO SO.
WHERE YOU CAN FIND MORE INFORMATION
In connection with the exchange offer, we have filed with the Securities and
Exchange Commission, or the SEC, a registration statement under the Securities
Act of 1933, relating to the exchange notes to be issued in the exchange offer.
As permitted by SEC rules, this prospectus omits information included in the
registration statement. For a more complete understanding of this exchange
offer, you should refer to the registration statement, including its exhibits.
The public may read and copy any reports or other information that we file
with the SEC at the SEC's public reference room, Room 1024 at Judiciary Plaza,
450 Fifth Street, N.W., Washington, D.C. 20549, or at the SEC's regional
offices located at 233 Broadway, New York, New York 10279, and Suite 1400, 500
West Madison Street, Chicago, Illinois 60661. The public may obtain information
on the operation of the public reference room by calling the SEC at
1-800-SEC-0330. These documents are also available to the public at the web
site maintained by the SEC at http://www.sec.gov. You may also obtain a copy of
the exchange offer registration statement at no cost by writing or telephoning
us at the following address:
PPL ENERGY SUPPLY, LLC
TWO NORTH NINTH STREET
ALLENTOWN, PENNSYLVANIA 18101-1179
ATTENTION: INVESTOR SERVICES DEPARTMENT
TELEPHONE: 1-800-345-3085
IN ORDER TO OBTAIN TIMELY DELIVERY, YOU MUST REQUEST DOCUMENTS FROM US NO
LATER THAN , 2002, WHICH IS FIVE DAYS BEFORE THE EXPIRATION DATE OF THE
EXCHANGE OFFER ON , 2002.
i
SUMMARY
THIS SUMMARY HIGHLIGHTS SELECTED INFORMATION FROM THIS PROSPECTUS AND DOES
NOT CONTAIN ALL THE INFORMATION THAT MAY BE IMPORTANT TO YOU. THIS SUMMARY DOES
NOT CONTAIN ALL OF THE INFORMATION THAT YOU SHOULD CONSIDER BEFORE MAKING ANY
DECISION CONCERNING THIS EXCHANGE OFFER. FOR A MORE COMPLETE UNDERSTANDING OF
THIS EXCHANGE OFFER, WE ENCOURAGE YOU TO READ THIS ENTIRE PROSPECTUS AND THE
DOCUMENTS TO WHICH WE REFER YOU.
THE EXCHANGE OFFER
ISSUANCE OF THE OLD NOTES..... The old notes were issued and sold on October
19, 2001 in a transaction not requiring
registration under the Securities Act.
THE EXCHANGE OFFER; NEW NOTES. We are offering to exchange up to $500,000,000
in aggregate principal amount of new notes
that have been registered under the Securities
Act for a like principal amount of old notes
of like tenor that noteholders properly tender
and do not withdraw before the expiration
date. The new notes may be exchanged only in
minimum denominations of $100,000 and integral
multiples of $1,000 in excess thereof. We will
issue the new notes on or promptly after the
expiration date. See "The Exchange Offer."
EXPIRATION DATE............... The exchange offer will expire at 5:00 p.m.,
New York City time, on , 2002 unless
extended. If extended, the term "expiration
date" will mean the latest date and time to
which the exchange offer is extended. We will
accept for exchange any and all old notes
which are properly tendered in the exchange
offer and not withdrawn before 5:00 p.m., New
York City time, on the expiration date
RESALE OF NEW NOTES........... Based on interpretive letters written by the
staff of the SEC to companies other than us,
we believe that, subject to certain
exceptions, the new notes may generally be
offered for resale, resold and otherwise
transferred by you, without compliance with
the registration and prospectus delivery
provisions of the Securities Act, if you
. acquire the new notes in the ordinary
course of your business;
. do not have an arrangement or
understanding with any person to
participate in a distribution of the new
notes;
. are not an affiliate of ours within the
meaning of Rule 405 under the Securities
Act; and
. are not a broker-dealer that acquired
the old notes directly from us.
If our belief is inaccurate, holders of new
notes who offer, resell or otherwise transfer
new notes in violation of the Securities Act
may incur liability under that Act. We will
not assume or indemnify holders against this
liability.
1
If you are a broker-dealer that purchased old
notes for your own account as part of
market-making or trading activities, you must
deliver a prospectus when you sell new notes.
We have agreed under the registration rights
agreement relating to the old notes to allow
you to use this prospectus for this purpose
for a period of 180 days after the
consummation of the exchange offer.
CONDITIONS TO THE EXCHANGE
OFFER....................... We may terminate the exchange offer before the
expiration date if we determine that our
ability to proceed with the exchange offer
could be materially impaired due to
. any legal or governmental actions,
. any new law, statute, rule or
regulation, or
. any interpretation by the staff of the
SEC of any existing law, statute, rule
or regulation.
TENDER PROCEDURES--
BENEFICIAL OWNER............ If you wish to tender old notes that are
registered in the name of a broker, dealer,
commercial bank, trust company or other
nominee, you should contact the registered
holder promptly and instruct the registered
holder to tender on your behalf.
IF YOU ARE A BENEFICIAL HOLDER, YOU SHOULD
FOLLOW THE INSTRUCTIONS RECEIVED FROM YOUR
BROKER OR NOMINEE WITH RESPECT TO TENDERING
PROCEDURES AND CONTACT YOUR BROKER OR NOMINEE
DIRECTLY.
TENDER PROCEDURES--
REGISTERED HOLDERS AND DTC
PARTICIPANTS................ If you are a registered holder of old notes
and you wish to participate in the exchange
offer, you must complete, sign and date the
letter of transmittal delivered with this
prospectus, or a facsimile thereof. If you are
a participant in The Depository Trust Company,
or DTC, and you wish to participate in the
exchange offer, you must instruct DTC to
transmit to the exchange agent a message
indicating that you agree to be bound by the
terms of the letter of transmittal. You should
mail or otherwise transmit the letter of
transmittal or facsimile (or agent's message
(as hereinafter defined)), together wtih your
old notes (in book-entry form if you are a
participant in DTC) and any other required
documentation to JPMorgan Chase Bank, as
exchange agent.
GUARANTEED DELIVERY PROCEDURES If you are a holder of old notes and you wish
to tender them, but they are not immediately
available or you cannot deliver them or the
letter of transmittal to the exchange agent
prior to the expiration date, you must tender
your old notes according to special guaranteed
delivery procedures. See "The Exchange
Offer--Procedures for Tendering--Registered
Holders and DTC Participants--Registered
Holders."
2
WITHDRAWAL RIGHTS............. You may withdraw tenders of old notes at any
time before 5:00 p.m., New York City time, on
the expiration date.
ACCEPTANCE OF OLD NOTES AND
DELIVERY OF NEW NOTES....... Subject to the satisfaction or waiver of the
conditions to the exchange offer, we will
accept for exchange any and all old notes that
are properly tendered and not withdrawn before
5:00 p.m., New York City time, on the
expiration date. The new notes will be
delivered promptly after the expiration of the
exchange offer.
CERTAIN FEDERAL INCOME TAX
CONSIDERATIONS.............. The exchange of new notes for old notes will
not be a taxable event for U.S. federal income
tax purposes. As a result, you will not
recognize any income, gain or loss with
respect to the exchange.
EXCHANGE AGENT................ JPMorgan Chase Bank
EFFECT ON HOLDERS OF OLD NOTES Any old notes that remain outstanding after
this exchange offer will continue to be
subject to restrictions on their transfer.
After this exchange offer, holders of old
notes will not (with limited exceptions) have
any further registration rights with respect
to the old notes. Any market for old notes
that are not exchanged could be adversely
affected by the consummation of this exchange
offer.
3
THE NEW NOTES
THE TERMS OF THE NEW NOTES WILL BE IDENTICAL IN ALL MATERIAL RESPECTS TO THE
TERMS OF THE OLD NOTES, EXCEPT THAT THE REGISTRATION RIGHTS AND RELATED
ADDITIONAL INTEREST PROVISIONS AND THE TRANSFER RESTRICTIONS APPLICABLE TO THE
OLD NOTES ARE NOT APPLICABLE TO THE NEW NOTES. THE NEW NOTES WILL EVIDENCE THE
SAME DEBT AS THE OLD NOTES. THE NEW NOTES AND THE OLD NOTES WILL BE GOVERNED BY
THE SAME INDENTURE. FOR MORE COMPLETE INFORMATION ABOUT THE NEW NOTES, SEE
"DESCRIPTION OF THE NEW NOTES."
ISSUER........................ PPL Energy Supply, LLC
THE NEW NOTES................. $500,000,000 principal amount of PPL Energy
Supply, LLC Senior Notes, 6.40% Exchange
Series A due 2011, which have been registered
under the Securities Act.
MATURITY...................... November 1, 2011.
INTEREST RATE................. 6.40% per annum, accruing from the last
interest payment date for the old notes, or if
no interest payment date has occurred, the
date of original issuance of the old notes,
calculated on the basis of a 360-day year of
twelve 30-day months.
INTEREST PAYMENT DATES........ Semi-annually on May 1 and November 1 of each
year, commencing May 1, 2002.
REDEMPTION.................... We may at our option redeem all or part of the
new notes at a redemption price equal to the
principal amount of the new notes to be
redeemed plus a make-whole premium described
below, together with accrued interest to the
redemption date. The redemption provisions are
more fully described in this prospectus under
"Description of the New Notes--Redemption."
The new notes have no sinking fund provisions.
RANKING....................... Like the old notes, the new notes will be
senior unsecured obligations of PPL Energy
Supply and will rank on a parity with PPL
Energy Supply's other unsecured and
unsubordinated indebtedness. Because we are a
holding company that conducts our operations
through subsidiaries, holders of the new notes
will generally have a position junior to the
claims of creditors, including debtholders, of
our subsidiaries. As of September 30, 2001,
our consolidated subsidiaries had
approximately $342 million of outstanding debt.
CERTAIN COVENANTS............. The Indenture limits our ability to incur
secured debt without providing that the new
notes will be equally and ratably secured with
such debt. These restrictions do not apply to
secured debt issued by subsidiaries, secured
debt not exceeding 10% of our consolidated
total assets and other specified exceptions.
The Indenture also restricts our ability to
sell our assets, and consolidate with or merge
into, or transfer or lease our assets
substantially as an entirety to, another
entity. However, these limitations are subject
to a number of important qualifications and
exceptions. See "Description of the New
Notes--Certain Covenants."
4
RISK FACTORS.................. An investment in the securities of PPL Energy
Supply involves certain risks, including risks
related to changes in commodity prices, the
competitive and regulatory markets in which we
operate, future operating costs and
performance of our electric generation
facilities and our need to comply with present
and future environmental laws and regulations.
You should carefully consider each of the
factors described in the section titled "Risk
Factors" before participating in the exchange
offer.
FORM.......................... The new notes will be represented by one or
more permanent global notes in fully
registered form. Each global note will be
deposited with the Trustee as custodian for
The Depository Trust Company, or DTC, and
registered in the name of DTC's nominee,
except in certain limited circumstances
described in this prospectus. See "Description
of the New Notes--Book-Entry Notes."
TRUSTEE AND PAYING AGENT...... JPMorgan Chase Bank (formerly known as The
Chase Manhattan Bank).
GOVERNING LAW................. The Indenture is, and the new notes will be,
governed by the laws of the State of New York.
5
PPL ENERGY SUPPLY
We are a growth-oriented energy company engaged in power generation and
marketing primarily in the northeastern and western United States and in the
delivery of electricity abroad.
. We own or control 9,762 MW of electric power generation capacity and we
intend to continue to acquire and develop new, low-cost and efficient
electric power generation facilities in key northeastern and western
markets. In addition, we are constructing or have announced the
development of new electric power projects in Arizona, Connecticut,
Illinois, New York, Pennsylvania and Washington representing an
additional 4,605 MW of power generation capacity. When we refer to MW in
this prospectus, we mean net megawatts with respect to generation
capacity that is currently in operation, and we mean gross megawatts
with respect to generation capacity that is in development.
. We market wholesale or retail energy in 42 states and Canada, deliver
electricity to approximately 4 million customers in the United Kingdom
and Latin America and provide energy-related services to businesses in
the mid-Atlantic and northeastern United States.
Our generation assets are managed as an integrated portfolio, with our
generation operations coordinating with our marketing, trading and risk
management activities.
ORGANIZATIONAL STRUCTURE. We are a holding company, and operate our
businesses through subsidiaries. Our principal operating subsidiaries include:
. PPL GENERATION, which serves as the holding company for our generation
businesses in the United States. PPL Generation currently owns or
controls a portfolio of domestic power generation assets with a total
capacity of 9,762 MW. These power plants are located in Pennsylvania
(8,509 MW), Montana (1,157 MW) and Maine (96 MW) and use
well-diversified fuel sources including coal, nuclear, natural gas, oil
and hydro. Our Pennsylvania generation assets consist primarily of
low-cost, baseload facilities and are located in the market-administered
PJM Interconnection, LLC, or PJM, the largest centrally-dispatched power
pool in the United States.
. PPL ENERGYPLUS, which markets or brokers electricity produced by PPL
Generation, along with purchased power and natural gas, in competitive
wholesale and retail markets, primarily in the northeastern and western
United States. In addition, PPL EnergyPlus sells electricity, natural
gas and energy services to retail customers in competitive markets in
Pennsylvania, New Jersey, Maine, Montana and Delaware. Under two
generation supply agreements with PPL Electric Utilities which extend
through 2009, PPL EnergyPlus sells electricity to PPL Electric
Utilities. PPL EnergyPlus supplies this electricity to meet PPL Electric
Utilities' "provider of last resort," or PLR, obligation to serve
electric customers who have not selected an alternative supplier under
the Pennsylvania Electricity Generation Customer Choice and Competition
Act, which we refer to as the Customer Choice Act, as well as PPL
Electric Utilities' contractual obligations to certain municipalities.
We estimate that approximately 60% of the electricity produced through
2009 by PPL Generation's existing facilities and projects that have been
announced or are currently under development will be sold to PPL
Electric Utilities under these two supply agreements. PPL EnergyPlus
also provides energy-related products and services, such as engineering
and mechanical contracting, construction and maintenance services, to
commercial and industrial customers.
. PPL GLOBAL, which is our development company, acquires and develops U.S.
generation projects. When these U.S. generation projects become
operational, PPL Generation will operate them as part of our integrated
portfolio. PPL Global also acquires, develops, owns and operates
international energy projects that are primarily focused on the
distribution of electricity. PPL Global currently owns and operates
electricity delivery businesses primarily in the United Kingdom and
Latin America.
6
We are a Delaware limited liability company, formed in November 2000. The
mailing address of our principal executive offices is Two North Ninth Street,
Allentown, Pennsylvania 18101-1179, and our telephone number is (610) 774-5151.
PPL CORPORATION
We are wholly-owned by PPL Corporation, a diversified energy and utility
holding company headquartered in Allentown, Pennsylvania. In addition to PPL
Energy Supply and our subsidiaries, PPL Corporation has a regulated electric
utility subsidiary, PPL Electric Utilities, which was incorporated in 1920. PPL
Electric Utilities delivers electricity to approximately 1.3 million customers
in eastern and central Pennsylvania, and supplies electricity related to its
PLR obligations. PPL Corporation also has a gas utility subsidiary, PPL Gas
Utilities Corporation, which provides gas delivery service to approximately
70,000 customers in Pennsylvania and Maryland.
Neither PPL Corporation nor any of its other subsidiaries or affiliates will
guarantee or provide other credit or funding support for the new notes.
In late-1996, the Customer Choice Act was enacted to deregulate the electric
generation supply market and provide a competitive market for generation of
electricity in Pennsylvania. Until June 30, 2000, PPL Electric Utilities
operated as a vertically-integrated electric utility that generated,
transmitted and distributed electricity to customers in its service territory.
On July 1, 2000, PPL Corporation completed a corporate realignment in order to
legally separate its competitive operations from its regulated utility
operations and to better position the PPL family of companies for success in
the competitive energy marketplace. As part of the realignment:
. PPL Electric Utilities transferred all of its electric generation
facilities and related assets to PPL Generation and all of its wholesale
energy marketing assets to PPL EnergyPlus;
. PPL Global transferred its U.S. operating electric generation
subsidiaries to PPL Generation; and
. PPL Generation, PPL EnergyPlus and PPL Global were contributed to
another PPL Corporation subsidiary, PPL Energy Funding.
In May 2001, PPL Energy Funding contributed a number of its subsidiaries,
including PPL Generation, PPL Global and PPL EnergyPlus, to us.
The chart below depicts a simplified corporate structure of PPL Corporation
and its significant operating subsidiaries.
[FLOW CHART]
PPL Corporation
PPL Energy Funding
PPL Energy Supply
PPL Global PPL EnergyPlus PPL Generation
. Develops/acquires . Performs all marketing . Owns/operates
domestic generation and trading activities domestic generation
. Develops/owns/ . Purchases fuels
operates international
projects
PPL Gas Utilities
PPL Electric Utilities Corporation PPL Services
7
RECENT DEVELOPMENTS
GENERATION SUPPLY AGREEMENT WITH PPL ELECTRIC UTILITIES. PPL EnergyPlus has
a full requirements contract to provide PPL Electric Utilities with electricity
sufficient for PPL Electric Utilities to meet its PLR obligations under the
Pennsylvania Customer Choice Act, through the end of 2001, at the
pre-determined "capped" rates that PPL Electric Utilities may charge its PLR
customers, regardless of the prevailing market price. As part of a settlement
order of the Pennsylvania Public Utility Commission, or PUC, PPL Electric
Utilities is required to provide this electricity at pre-determined capped
rates through 2009 to customers not choosing an alternate electric supplier.
While rates for generation supply vary by customer class, the settlement order
provides for average rates ranging from 4.16 cents per kWh in 2001, increasing
to 5.02 cents per kWh in 2009. PPL Electric Utilities solicited bids from
energy suppliers to secure enough supply to meet its PLR obligations through
2009. PPL EnergyPlus was the successful bidder, and, in June 2001, entered into
a contract to provide electricity to PPL Electric Utilities sufficient for it
to meet its PLR obligation from 2002 through 2009, at the pre-determined capped
rates PPL Electric Utilities is entitled to charge its customers during this
period.
Under this contract, PPL EnergyPlus is to provide PPL Electric Utilities
with electricity at PPL Electric Utilities' pre-determined capped prices. PPL
EnergyPlus has received an up-front $90 million payment to offset differences
between the revenues expected under the pre-determined capped rates and
projected market prices through the life of the supply agreement (as projected
by PPL EnergyPlus when it submitted its bid). As a result, PPL EnergyPlus has
an eight-year contract effectively at market-based prices. We estimate that
approximately 60% of the electricity produced through 2009 by PPL Generation's
existing facilities and projects that have been announced or are currently
under development will be sold to PPL Electric Utilities under the two
generation supply agreements. These generation supply agreements with PPL
Electric Utilities help us to maintain an appropriate balance between long-term
wholesale contracts and sales in short-term wholesale markets.
In July 2001, the new PLR contract was approved by the PUC and was accepted
for filing by the Federal Energy Regulatory Commission, or FERC.
SUPPLY CONTRACT WITH THE MONTANA POWER COMPANY. On October 15, 2001, we
reached an agreement to provide 450 megawatts of electricity supply to The
Montana Power Company, which we refer to as Montana Power, over a five-year
period beginning July 1, 2002. Under the agreement, PPL EnergyPlus will supply
300 megawatts of baseload electricity and 150 megawatts of on-peak electricity
at an expected average annual price of $32 per megawatt-hour. As a result of
this agreement and other wholesale and retail agreements, we will have about
two-thirds of the output of our Montana power plants under long-term contracts
beginning in July 2002. The agreement was reached as a result of a bidding
process by Montana Power. PPL EnergyPlus has filed the agreement for acceptance
by the FERC.
Until the new contract goes into effect, PPL EnergyPlus will continue to
supply Montana Power under existing arrangements.
EXPOSURE TO ENRON. In connection with the December 2, 2001 bankruptcy
filings by Enron Corp. and its affiliates ("Enron"), certain of our
subsidiaries have terminated certain electricity and gas agreements with Enron.
We estimate our 2001 earnings exposure associated with termination of these
contracts to be approximately $10 million, and will record this impact in our
financial statements. Additionally, certain of these contracts with Enron
extended through 2006, and were at prices more favorable to us than current
market prices. However, there is no further accounting charge to be recorded.
We expect to make a claim in Enron's bankruptcy proceeding with respect to all
amounts payable by Enron resulting from the termination of these contracts.
8
In addition, WPDH is a 15 percent equity investor in the 1,875 MW Teesside
Power Station, located in northern England. Enron participates through its
European affiliates as an owner, an operator and a power purchaser of the
project. We cannot determine, at this time what effect, if any, Enron's
circumstances could have on Teesside's operational and financial performance.
At November 30, 2001, WPDH's total investment in Teesside was approximately 46
million pounds, or approximately $66 million, based on exchange rates at that
date. PPL Global holds a 51 percent economic interest in WPDH, but shares
control with Mirant. PPL Global accounts for its investment in WPDH under the
equity method of accounting.
BUSINESS STRATEGY
Our objective is to be a leading, asset-based provider of wholesale and
retail energy and energy-related products and services in the northeastern and
western United States. We plan to achieve this objective by generating and
selling competitively priced energy in large, high-growth markets. We also plan
to continue to operate high-quality energy delivery businesses in selected
regions around the world. The key elements of our strategy are as follows:
DEVELOP AND ACQUIRE ADDITIONAL GENERATION FACILITIES IN OUR TARGET MARKETS
Our objective is to continue to expand our ownership or control of domestic
generation capacity in our target markets in the northeastern and western
United States. We currently own or control 9,762 MW of
8.1
generation capacity in Pennsylvania, Montana and Maine. In addition, we are
constructing or have announced the development of new power projects in
Arizona, Connecticut, Illinois, New York, Pennsylvania and Washington
representing an additional 4,605 MW of generation capacity. These facilities
will consist of gas-fired combined and simple cycle technology-based generation
units that are expected to commence operations at various times between 2001
and 2005. We also will continue to actively evaluate opportunities to acquire
operating generation facilities or develop new generation projects in our
target markets. We believe that the northeastern and western regions of the
United States are particularly attractive markets because the existing and
projected supply and demand dynamics for power in these regions will require
the construction of new generation facilities to meet expected increased
customer demand.
OPERATE A DIVERSE AND LOW-COST PORTFOLIO OF GENERATION ASSETS
We seek to operate an efficient and low-cost generation asset portfolio that
is diversified as to geography, fuel source and operating characteristics. Our
current generation facilities, as well as our new generation projects under
development or construction, are strategically located in our target markets
and provide us with a geographically diverse presence in the northeastern and
western United States, which helps to mitigate the risks resulting from
regional price differences. Our current portfolio of generation assets is also
well-diversified by fuel type with 46% of our total generation capacity coming
from coal, 22% from natural gas/oil, 20% from nuclear, 8% from hydro and 4%
from other, as of September 30, 2001. Our coal-fired capacity is located in the
eastern and western United States and benefits from the low fuel costs
resulting from the relatively close proximity of our plants to coal fields and
low transportation costs, our extensive experience in acquiring low-cost coal
and our highly-efficient coal-fired plant technology. The generation assets are
also diversified with respect to dispatch, consisting of 74% baseload units,
20% intermediate load units and 6% peaking load units, as of September 30,
2001. Our current generation portfolio is weighted towards low-cost baseload
generation units, which helps reduce the volatility of our revenues. Our new
development projects involve new intermediate and peaking facilities utilizing
natural gas-fired, combined and simple cycle technology-based generation units.
These new units will allow us to further diversify our fuel mix, enhance our
ability to capture the potential benefits of peak period pricing and provide us
with additional operational flexibility and ancillary service revenues.
PURSUE ADDITIONAL REVENUES THROUGH ASSET-BASED TRADING OPPORTUNITIES
We intend to grow and diversify our revenue base by continuing to capitalize
on energy marketing and trading opportunities in the increasingly deregulated
United States electricity market. We believe that our ability to market and
trade around our physical portfolio of generation assets through our integrated
generation, marketing and trading functions will provide us with attractive
opportunities to grow our revenues. In pursuing these opportunities, we attempt
to limit our financial exposure by following a comprehensive risk management
program. In particular, and consistent with our asset-based strategy, we
generally seek to execute contractual commitments for energy sales that do not
exceed our ability to produce the energy required. We employ sophisticated
trading practices to capture regional arbitrage opportunities and maximize the
value of our generation capacity. In addition, we seek to capture a diverse
stream of revenues and avoid over-reliance on any one market or type of
customer. As a result of our generation asset portfolio, our asset-based
approach to marketing and trading and our comprehensive risk management
program, we believe we are well-positioned to grow our revenues while limiting
the potential impacts of energy price volatility.
CAPITALIZE ON SELECTED INTERNATIONAL TRANSMISSION AND DISTRIBUTION
OPPORTUNITIES
Our international strategy is focused on effectively managing our current
portfolio of energy transmission and distribution businesses in Latin America
(primarily Brazil, Chile and El Salvador) and the United Kingdom. We have
concentrated our development activities in Latin America, as we believe this
region encourages investment in distribution assets and exhibits a potential
for high growth in the demand for electric distribution
9
and related services. We believe our knowledge and experience in operating
efficient, low-cost energy delivery businesses will provide the greatest
benefit in Latin America.
In the United Kingdom, we have focused on investing in electricity
distribution businesses that operate in a stable operating and regulatory
environment. We believe these distribution companies will produce strong and
predictable cash flows due to stable demand and regulated tariffs, and provide
opportunities to improve efficiencies relative to operating costs, capital
investments and reliability of service.
COMPETITIVE ADVANTAGES
We believe we are well-positioned to successfully compete in the markets in
which we have chosen to focus. Our significant competitive advantages include:
. 9,762 MW of low-cost generation capacity that we own or control in our
target U.S. markets (Pennsylvania, Montana and Maine);
. 4,605 MW of generation that has been announced or is under development
or construction in Arizona, Connecticut, Illinois, New York,
Pennsylvania and Washington;
. A generation portfolio diversified by:
. Region, across the United States, and within regions through our
participation in multiple markets; I.E., PJM and the New England
Power Pool, or NEPOOL, in the East, and the Western States
Coordinating Council, or WSCC, in the West;
. Fuel sources:
. 4,480 MW of coal-fired generation;
. 2,146 MW of gas and/or oil-fired generation;
. 1,995 MW of nuclear-fueled generation;
. 803 MW of hydroelectric generation; and
. 338 MW of "other" generation (various qualifying facilities); and
. Operating type:
. 7,271 MW of baseload units;
. 1,940 MW of intermediate load units; and
. 551 MW of peaking load units;
. An eight-year contract with PPL Electric Utilities to provide all of its
PLR load requirements, which positions us to lock in attractive margins
on a substantial portion of our anticipated energy sales during this
period;
. Our extensive knowledge, experience and proven track record in power
plant and power systems operations, allowing us to use our assets in a
manner that maximizes value;
. An integrated generation, marketing and fuel procurement strategy;
. A management team that is comprised of seasoned individuals who have
long-standing experience with our industry, market conditions, commodity
trading and risk management, business development and labor relations;
. An existing comprehensive risk management program designed to
proactively monitor and manage our exposure to market price risks; and
. A focused attention on international electric transmission and
distribution operations in two regions-the United Kingdom and Latin
America.
10
SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA
You should read the following summary historical consolidated financial data
together with our consolidated financial statements and the related notes and
the "Selected Financial Information and Operating Data" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere in this prospectus.
FOR THE
NINE MONTHS ENDED FOR THE YEARS ENDED
SEPTEMBER 30, DECEMBER 31,
------------------- ------------------------
2001 2000 2000 1999 1998
------ ------- ------- -------- -----
(MILLIONS OF DOLLARS, EXCEPT RATIOS)
STATEMENT OF INCOME DATA:
Operating revenues................................. $3,420 $ 1,972 $ 3,121 $ 974 $ 125
Operating income (loss)............................ 725 241 464 (81) 21
Other income (expense):
Interest expense................................ (35) (86) (127) (52) (25)
Other, net...................................... 53 22 34 83 10
------ ------- ------- -------- -----
Total other income (expense).................. 18 (64) (93) 31 (15)
------ ------- ------- -------- -----
Income (loss) from continuing operations before
income taxes and minority interest................ 743 177 371 (50) 6
Income tax expense (benefit)....................... 249 53 125 (29) (6)
Minority interest.................................. 4 4 4 14 --
------ ------- ------- -------- -----
Net income (loss).................................. $ 490 $ 120 $ 242 $ (35) $ 12
====== ======= ======= ======== =====
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in) operating activities $ 354 $ 231 $ 615 $ (249) $ 14
Net cash used in investing activities.............. (521) (406) (1,351) (926) (305)
Net cash provided by financing activities.......... 409 170 784 1,201 304
OTHER FINANCIAL DATA:
EBITDA/(1)/........................................ $ 892 $ 309 $ 583 $ 8 $ 32
Ratio of Earnings to Fixed Charges/(2)/............ 8.19/(3)/ /(3)/ 2.99 /(4)/ 1.12
AS OF AS OF
SEPTEMBER 30, 2001 DECEMBER 31,
------------------- -------------
AS
ACTUAL ADJUSTED/(5)/ 2000 1999
------ ------------ ------ ------
(MILLIONS OF DOLLARS)
BALANCE SHEET DATA:
Cash and cash equivalents........................................ $ 372 $ 861 $ 130 $ 82
Property, plant and equipment, net............................... 3,507 3,507 3,389 1,235
Investments...................................................... 1,801 1,801 1,118 407
Total assets..................................................... 8,114 8,603 7,463 2,721
Short-term debt payable to affiliated companies.................. -- -- 2,120 863
Other short-term debt including current portion of long-term debt 141 141 203 383
Senior notes..................................................... -- 500 -- --
Other long-term debt............................................. 201 201 159 33
Total debt.................................................... 342 842 2,482 1,279
Member's equity.................................................. 5,594 5,594 2,577 922
(FOOTNOTES ON FOLLOWING PAGE)
11
- --------
/(1)/EBITDA is income (loss) before extraordinary items plus interest expense,
income taxes and depreciation. EBITDA is a measure of financial performance
not defined under generally accepted accounting principles, which you should
not consider in isolation or as a substitute for net income, cash flows from
operations or other income or cash flow data prepared in accordance with
generally accepted accounting principles or as a measure of a company's
profitability or liquidity. In addition, EBITDA may not be comparable to
similarly titled measures presented by other companies and could be
misleading because all companies and analyses do not calculate it in the
same fashion.
/(2)/The Ratio of Earnings to Fixed Charges is calculated by dividing earnings
by fixed charges. For this purpose, "earnings" means net income (loss)
before income taxes and before adjustment for minority interests in
consolidated subsidiaries or income (loss) from equity investees, plus fixed
charges, plus amortization of capitalized interest, plus distributed income
of equity investees, less interest capitalized. "Fixed charges" means
interest expense, plus interest capitalized, plus amortization of debt
issuance costs, plus the estimated interest component of rent expense.
/(3)/The Ratio of Earnings to Fixed Charges is calculated for the 12-month
period ending September 30, 2001. This ratio was not calculated for the
12-month period ending September 30, 2000.
/(4)/Earnings did not cover fixed charges by $105 million in 1999, primarily
due to a loss incurred by PPL EnergyPlus, and undistributed earnings of PPL
Global's equity method investments.
/(5)/Assumes net proceeds of $489 million from the issuance and sale of old
notes (after discounts and commissions and estimated offering and exchange
offering expenses).
12
INDEPENDENT CONSULTANTS' REPORTS
An independent engineering consultant, Stone & Webster Consultants, has
prepared an Independent Technical Review addressing specific technical,
environmental and economic aspects of our energy and energy-related facilities.
We have attached a summary of that review as Annex A to this prospectus. We
advise you that the Summary Independent Technical Review is dated August 15,
2001, and information contained in that report may only be accurate as of that
date. We have not requested, nor do we intend to request, that Stone & Webster
Consultants update the information in the Summary Independent Technical Review.
Stone & Webster Consultants' Summary Independent Technical Review includes
its technical assessment of all of our major assets (except for those assets of
WPD Investment Holdings Ltd. and WPD Holdings UK, which we refer to as WPDL and
WPDH, respectively), based on, among other things, its review of the available
technical data, historical performance and cost data, and visits to significant
and/or representative facilities. Stone & Webster Consultants' report presents
its findings and conclusions regarding:
. the conditions and expected remaining life of the assets;
. projected capital costs, operating and maintenance expenses, and
environmental issues relating to the future operation and maintenance of
the facilities; and
. pro forma financial projections of cash flows under base case and
sensitivity assumptions.
An independent market consultant, ICF Resources, Inc., has prepared a report
that presents ICF's forecast and market analysis for the PJM West, NEPOOL,
Arizona/New Mexico and Montana markets, including the economic competitiveness
of our electric generation facilities within these markets. The report also
provides dispatch and revenue projections for current development projects
being pursued in Arizona, Illinois, New York, Pennsylvania and Washington. A
copy of the Independent Market Consultant's Report is attached as Annex B to
this prospectus. We advise you that the Independent Market Consultant's Report
is dated June 2001, and information contained in that report may only be
accurate as of that date. We have not requested, nor do we intend to request,
that ICF Resources update the information in the Independent Market
Consultant's Report.
The Summary Independent Technical Review and the Independent Market
Consultant's Report rely on assumptions regarding material contingencies and
other matters that are not within our control or the control of Stone & Webster
Consultants, ICF Resources or any other person. The Summary Independent
Technical Review and the Independent Market Consultant's Report summarize the
work of Stone & Webster Consultants and ICF Resources, respectively, up to the
dates of the respective reports, and changed conditions occurring or becoming
known after the dates of the respective reports could affect the findings and
conclusions contained in such reports. While each of Stone & Webster
Consultants and ICF Resources believes its assumptions to be reasonable for
purposes of preparing its respective report, these assumptions are inherently
subject to significant uncertainties and actual results may differ materially
from those projected. The predictions, estimates and assumptions that underlie
these reports may also differ from those that other experts specializing in the
electricity industry might present. Potential investors should carefully review
the Summary Independent Technical Review and the Independent Market
Consultant's Report, as well as the qualifications in those reports.
The financial projections prepared by Stone & Webster Consultants are
summarized below. These projections were not prepared with a view toward
compliance with published guidelines of the SEC, the guidelines established by
the American Institute of Certified Public Accountants for preparation and
presentation of financial projections, or generally accepted accounting
principles expected to be in effect during the period of the projections. The
projections included in this summary have been derived from the base case
assumptions set forth in the Summary Independent Technical Review, and are
subject to the qualifications, limitations and exclusions set forth therein,
but we believe that the projections are supported by the Summary Independent
Technical Review and were prepared on a reasonable basis.
PricewaterhouseCoopers LLP, our independent
13
accountants, have neither examined nor compiled these projections and
accordingly, PricewaterhouseCoopers LLP does not express an opinion or any
other form of assurance with respect thereto. Moreover, there will be
differences between actual and prospective results and those differences may be
material. The PricewaterhouseCoopers LLP report included in this prospectus
relates to PPL Energy Supply, LLC's historical financial statements for the
years ended December 31, 2000, 1999 and 1998. It does not extend to the
projections and should not be read to do so.
YEAR ENDING DECEMBER 31,
-------------------------------------------
2001/(1)/ 2002 2003 2004 2005 2010
-------- ------ ------ ------ ------ ------
SELECTED PROJECTED FINANCIAL DATA
(MILLIONS OF DOLLARS, EXCEPT RATIOS)
Total Revenues/(2)/................... $2,485 $2,999 $2,796 $2,939 $3,492 $4,589
Total Operating Income/(3)/........... 1,027 1,386 1,010 1,010 1,271 1,939
Capital Expenditures/(4)/............. 370 328 307 302 299 252
Cash Available for Debt Service/(5)/.. 657 1,058 703 709 972 1,687
Total Debt/(6)/....................... 722 716 768 757 767 762
Debt Service Coverage Ratio/(7)/...... 5.18 17.53 11.29 11.07 15.19 26.36
YEAR ENDING DECEMBER 31,
-----------------------------------------------
AVERAGE AVERAGE
2001/(1)/ 2002 2003 2004 2005 2001-2005 2001-2010
-------- ---- ---- ---- ---- --------- ---------
SELECTED PROJECTED OPERATING DATA
Projected Percentage Sales
Distribution by MWH Generated
Contract...................... 76% 69% 68% 63% 54% 66% 54%
Market........................ 24% 31% 32% 37% 46% 34% 46%
- --------
/(1)/The 2001 projections are not based on actual market prices or electricity
generation. Actual data for 2001 may differ significantly from that shown.
/(2)/Total Revenues do not include certain operations of PPL EnergyPlus'
marketing and trading organization and certain unconsolidated international
operations including our investments in the United Kingdom.
/(3)/Total Operating Income is operating revenues less operating expenses,
which includes our lease expenses for PPL Montana and leased turbine
generators, less general and administrative expenses.
/(4)/Excludes expenditures to be funded under operating leases for simple-cycle
peaking turbines and the combined-cycle facility in Lower Mt. Bethel that
are included in the Company's capital expenditure requirements for the years
2001 through 2005 as set forth under "Management's Discussion and Analysis
of Financial Condition and Results of Operations--Capital Expenditure
Requirements" herein.
/(5)/Cash Available for Debt Service is Total Operating Income less Capital
Expenditures.
/(6)/Total Debt is comprised of assumed long-term debt (including current
portion), including the senior notes and short-term debt, including debt of
PPL Global's consolidated foreign subsidiaries.
/(7)/Debt Service Coverage Ratio is calculated by dividing cash available for
debt service by projected interest expense.
14
RISK FACTORS
IN ADDITION TO THE OTHER INFORMATION IN THIS PROSPECTUS, YOU SHOULD CONSIDER
THE FACTORS DESCRIBED BELOW. THE RISKS AND UNCERTAINTIES DESCRIBED BELOW ARE
NOT THE ONLY RISKS WE FACE. ADDITIONAL RISKS AND UNCERTAINTIES NOT PRESENTLY
KNOWN TO US OR THAT WE CURRENTLY DEEM IMMATERIAL MAY IMPAIR OUR BUSINESS
OPERATIONS. EACH OF THE RISKS DESCRIBED BELOW COULD HAVE A MATERIAL ADVERSE
EFFECT ON OUR BUSINESS, FINANCIAL CONDITIONS OR RESULTS OF OPERATIONS AND COULD
RESULT IN A LOSS OR A DECREASE IN THE VALUE OF YOUR NEW NOTES.
RISKS RELATED TO OUR GENERATION AND MARKETING BUSINESSES
CHANGES IN COMMODITY PRICES MAY INCREASE THE COST OF PRODUCING POWER OR
DECREASE THE AMOUNT WE RECEIVE FROM SELLING POWER, WHICH COULD ADVERSELY
AFFECT OUR FINANCIAL PERFORMANCE.
Our generation and marketing businesses are subject to changes in power
prices or fuel costs, which may impact our financial results and financial
position by increasing the cost of producing power or decreasing the amount we
receive from the sale of power. The market prices for these commodities may
fluctuate substantially over relatively short periods of time. Among the
factors that could influence such prices are:
. prevailing market prices for coal, natural gas, fuel oil and other fuels
used in our generation facilities, including associated transportation
costs and supplies of such commodities;
. demand for energy and the extent of additional supplies of energy
available from current or new competitors;
. capacity and transmission service into, or out of, our markets;
. changes in the regulatory framework for wholesale power markets;
. liquidity in the general wholesale electricity market; and
. weather conditions impacting demand for electricity.
In the absence of or upon expiration of power sales agreements, we must sell
all or a portion of the energy, capacity and other products from our facilities
into the competitive wholesale power markets. Unlike most other commodities,
energy products cannot be stored and must be produced concurrently with their
use. As a result, the wholesale power markets are subject to significant price
fluctuations over relatively short periods of time and can be unpredictable. In
addition, the price we can obtain for power sales may not change at the same
rate as changes in fuel and other costs. Given the volatility and potential for
material differences between actual power prices and fuel and other costs, if
we are unable to secure or maintain long-term purchase agreements for our power
generation facilities, our revenues would be subject to increased volatility
and our financial results may be materially adversely affected.
OUR FACILITIES MAY NOT OPERATE AS PLANNED, WHICH MAY HAVE AN ADVERSE EFFECT
ON OUR FINANCIAL PERFORMANCE.
Our operation of power plants involves many risks, including the breakdown
or failure of generation equipment or other equipment or processes, accidents,
labor disputes, fuel interruption and operating performance below expected
levels. In addition, weather-related incidents and other natural disasters can
disrupt both generation and transmission delivery systems. Operation of our
power plants below expected capacity levels may result in lost revenues or
increased expenses, including higher maintenance costs and penalties or damages.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FUEL SUPPLIES, WHICH COULD ADVERSELY
AFFECT OUR RESULTS OF OPERATIONS.
We purchase fuel from a number of suppliers. Any disruption in the delivery
of fuel, including disruptions as a result of weather, labor relations or
environmental regulations affecting our fuel suppliers, could adversely affect
our ability to operate our facilities and thus our results of operations.
15
WE HAVE AGREED TO PROVIDE ELECTRICITY TO PPL ELECTRIC UTILITIES IN AMOUNTS
SUFFICIENT TO SATISFY ITS PLR OBLIGATIONS AT PRICES WHICH MAY BE BELOW OUR
COST, WHICH COULD ADVERSELY AFFECT OUR OPERATING RESULTS.
PPL Electric Utilities has PLR obligations to serve those electric retail
customers that did not select an alternate supplier under the Customer Choice
Act. PPL EnergyPlus has entered into long-term contracts to supply all of PPL
Electric Utilities' electricity requirements at agreed prices through 2009.
This obligation currently represents a significant portion of the normal
operating capacity of our existing generation assets. The prices we receive are
established under the contracts and have little or no relationship to the cost
to us of supplying this power. This means that we are required to absorb
increasing costs, including the risk of fuel price increases and increased
costs of production.
The PLR contract obligations do not provide us with any guaranteed level of
sales. If the customers of PPL Electric Utilities obtain service from alternate
suppliers, which they are entitled to do at any time, our sales of power under
the contract may decrease. Alternatively, customers could switch back to PPL
Electric Utilities from alternative suppliers, which may increase demand above
our facilities' available capacity. Thus, any such switching by customers could
have a material adverse effect on our results of operations or financial
position.
WE ARE SUBJECT TO THE RISKS OF NUCLEAR GENERATION.
Through PPL Susquehanna, we own a 90% undivided interest in the two nuclear
generating units that make up the 2,217 MW Susquehanna station. As a result,
nuclear generation accounts for about 20% of our generation capacity. We are,
therefore, also subject to the risks of nuclear generation, which include the
following:
. the potential harmful effects on the environment and human health
resulting from the operation of nuclear facilities and the storage,
handling and disposal of radioactive materials;
. limitations on the amounts and types of insurance commercially available
to cover losses that might arise in connection with nuclear operations;
and
. uncertainties with respect to the technological and financial aspects of
decommissioning nuclear plants at the end of their licensed lives.
The Nuclear Regulatory Commission, or NRC, has broad authority under federal
law to impose licensing and safety-related requirements for the operation of
nuclear generation facilities. In the event of non-compliance, the NRC has the
authority to impose fines or shut down a unit, or both, depending upon its
assessment of the severity of the situation, until compliance is achieved.
Revised safety requirements promulgated by the NRC could necessitate
substantial capital expenditures at nuclear plants, such as our Susquehanna
plant. In addition, although we have no reason to anticipate a serious nuclear
incident at our Susquehanna plant, if an incident did occur, it could have a
material adverse effect on our results of operations or financial condition.
MANY OF OUR FACILITIES HAVE A LIMITED HISTORY OPERATING IN A COMPETITIVE
ENVIRONMENT.
The facilities that were transferred to us by PPL Electric Utilities,
Montana Power and The Bangor Hydro-Electric Company, which we refer to as
Bangor Hydro, were operated within vertically-integrated, regulated utilities
that sold electricity to consumers at prices based on predetermined rates set
by state public utility commissions. Unlike regulated utilities, we are not
guaranteed any rate of return on our capital investments through predetermined
rates, and our revenues and results of operations are likely to depend, in
large part, upon prevailing market prices for electricity in our regional
markets and other competitive markets, the volume of demand, capacity factors
and ancillary services. We have limited history operating these facilities in a
market-based competitive environment, and we may not be able to operate them
successfully in such an environment.
CHANGES IN TECHNOLOGY MAY SIGNIFICANTLY IMPACT OUR BUSINESS BY IMPAIRING THE
VALUE OF OUR POWER PLANTS.
A basic premise of our business is that generating power at central power
plants achieves economies of scale and produces electricity at a relatively low
price. There are other technologies that produce electricity, most
16
notably fuel cells, microturbines, windmills and photovoltaic (solar) cells.
Research and development activities are ongoing to seek improvements in the
alternate technologies. It is possible that advances will reduce the cost of
alternate methods of electric production to a level that is equal to or below
that of most central station electric production. If this were to happen, the
value of our power plants may be significantly impaired. Changes in technology
could also alter the ways in which retail electric customers buy electricity or
meet their electricity needs, thereby adversely affecting our financial results.
WE MAY NOT BE ABLE TO SUCCESSFULLY MANAGE THE RISKS ASSOCIATED WITH SELLING
AND MARKETING PRODUCTS IN THE WHOLESALE POWER MARKETS.
We purchase and sell power at the wholesale level under FERC-authorized,
market-based tariffs throughout the United States and also enter into
short-term agreements to market available energy and capacity from our
generation assets with the expectation of profiting from market price
fluctuations. If we are unable to deliver firm capacity and energy under these
agreements, we could be required to pay damages. These damages would generally
be based on the difference between the market price to acquire replacement
capacity or energy and the contract price of the undelivered capacity or
energy. Depending on price volatility in the wholesale energy markets, such
damages could be significant. Extreme weather conditions, unplanned power plant
outages, transmission disruptions, non-performance by counterparties (or their
counterparties) with which we contract, and other factors could affect our
ability to meet our obligations, or cause significant increases in the market
price of replacement capacity and energy. Although we attempt to mitigate these
risks, there can be no assurance that we will be able to fully meet our
obligations, that we will not experience counterparty non-performance or that
we will not be required to pay damages for failure to perform.
In addition, the independent system operators, or ISOs, that oversee the
transmission systems in certain wholesale power markets have in the past been
authorized to impose, and may continue to impose, price limitations and other
mechanisms to address volatility in the power markets. These types of price
limitations and other mechanisms may adversely impact the profitability of our
wholesale power marketing and trading business. Given the extreme volatility
and lack of meaningful long-term price history in many of these markets and the
imposition of price limitations by regulators, independent system operators or
other market operators, we can offer no assurance that we will be able to
operate profitably in all wholesale power markets.
WE DO NOT ALWAYS HEDGE AGAINST RISKS ASSOCIATED WITH COMMODITY ENERGY AND
FUEL PRICES.
We attempt to mitigate risks associated with satisfying our contractual
power sales arrangements by reserving generation capacity to deliver
electricity to satisfy our net firm sales contracts and, when necessary, by
purchasing firm transmission service. We also routinely enter into contracts,
such as fuel and power purchase and sale commitments, to hedge our exposure to
weather conditions, fuel requirements and other energy-related commodities. We
may not, however, hedge the entire exposure of our operations from commodity
price volatility. To the extent we fail to hedge against commodity price
volatility, our results of operations and financial position may be affected
either favorably or unfavorably.
OUR TRADING, MARKETING AND RISK MANAGEMENT POLICIES MAY NOT WORK AS PLANNED.
We actively manage the market risk inherent in our energy and fuel, debt and
foreign currency positions. Nonetheless, adverse changes in energy and fuel
prices, interest rates and foreign currency exchange rates may result in
economic losses in our earnings or cash flows and our balance sheet under
applicable accounting rules. Our trading, marketing and risk management
procedures may not always be followed or may not work as planned. As a result,
we cannot predict with precision the impact that our trading, marketing and
risk management decisions may have on our business, operating results or
financial position.
In addition, our trading, marketing and risk management activities are
exposed to the credit risk that counterparties that owe us money or energy will
breach their obligations. We have established risk management
17
policies and programs, including credit policies to evaluate counterparty
credit risk. However, if counterparties to these arrangements fail to perform,
we may be forced to enter into alternative hedging arrangements or honor
underlying commitments at then-current market prices. In that event, our
financial results are likely to be adversely affected.
OUR OPERATING RESULTS MAY FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS.
Electrical power supply is a seasonal business. For example, in some parts
of the country, demand for, and market prices of, electricity peak during the
hot summer months, while in other parts of the country such peaks occur in the
cold winter months. As a result, our overall operating results in the future
may fluctuate substantially on a seasonal basis. The pattern of this
fluctuation may change depending on the nature and location of the facilities
we acquire and the terms of our contracts to sell electricity.
WE RELY ON SOME TRANSMISSION AND DISTRIBUTION ASSETS THAT WE DO NOT OWN OR
CONTROL TO DELIVER OUR WHOLESALE ELECTRICITY AND NATURAL GAS. IF TRANSMISSION
IS DISRUPTED, OR IF CAPACITY IS INADEQUATE, OUR ABILITY TO SELL AND DELIVER
POWER MAY BE HINDERED.
We depend on transmission and distribution facilities owned and operated by
utilities and other energy companies to deliver the electricity and natural gas
we sell to the wholesale market, as well as the natural gas we purchase to
supply some of our electric generation facilities. If transmission is
disrupted, or if capacity is inadequate, our ability to sell and deliver
products and satisfy our contractual obligations may be hindered.
The FERC has issued regulations that require wholesale electric transmission
services to be offered on an open-access, non-discriminatory basis. Although
these regulations are designed to encourage competition in wholesale market
transactions for electricity, there is the potential that fair and equal access
to transmission systems will not be available or that sufficient transmission
capacity will not be available to transmit electric power as we desire. We
cannot predict the timing of industry changes as a result of these initiatives
or the adequacy of transmission facilities in specific markets.
RISKS RELATED TO OUR BUSINESS GENERALLY AND TO OUR INDUSTRY
THE ENERGY INDUSTRY IS RAPIDLY CHANGING AND INTENSELY COMPETITIVE, WHICH MAY
ADVERSELY AFFECT OUR ABILITY TO OPERATE PROFITABLY.
We face intense competition in our energy supply, distribution and
development businesses. A number of our competitors, including domestic and
international energy companies and other global power providers, have more
extensive experience operating in unregulated markets, larger staffs and/or
greater financial resources than we do. In addition, many of the regions in
which we operate have implemented or are considering implementing regulatory
initiatives designed to increase competition. For example, regulations
encouraging industry deregulation and privatization continue to cause the
disaggregation of vertically integrated utilities into separate generation,
transmission and distribution businesses in the United States and abroad.
Moreover, the FERC has implemented regulatory changes designed to increase
access to transmission grids by utility and non-utility purchasers and sellers
of electricity. As a result, a significant number of additional competitors
could become active in the generation segment of our industry. This competition
may negatively impact our ability to sell energy and related products and the
prices which we may charge for such products, which could adversely affect our
results of operations and our ability to grow our business.
In addition, while demand for electricity is generally increasing throughout
the United States, the rate of construction and development of new electric
assets may exceed the increase in demand in some regional markets. The
commencement of commercial operation of new facilities in the regional markets
where we own or control generation capacity will likely increase the
competitiveness of the wholesale power market in those regions, which could
have a material adverse effect on our business and financial condition.
18
OUR BUSINESS IS SUBJECT TO EXTENSIVE REGULATION.
Our U.S. generation subsidiaries are exempt wholesale generators, or EWGs,
which sell electricity into the wholesale market. Generally, our EWGs are
subject to regulation by the FERC. The FERC has authorized us to sell
generation from our facilities at market-based prices. The FERC retains the
authority to modify or withdraw our market-based rate authority and to impose
"cost of service" rates if it determines that the market is not workably
competitive, that we possess market power or that we are not charging just and
reasonable rates. Any reduction by the FERC of the rate we may receive or any
unfavorable regulation of our business by state regulators could materially
adversely affect our results of operations.
The acquisition, ownership and operation of power generation facilities
require numerous permits, approvals, licenses and certificates from federal,
state and local governmental agencies. We may not be able to obtain or maintain
all required regulatory approvals. If there is a delay in obtaining any
required regulatory approvals or if we fail to obtain or maintain any required
approval or comply with any applicable law or regulation, the operation of our
assets and our sales of electricity could be prevented or delayed or become
subject to additional costs.
OUR BUSINESS OPERATES IN DEREGULATED SEGMENTS OF THE ELECTRIC POWER INDUSTRY
CREATED BY RESTRUCTURING INITIATIVES AT BOTH STATE AND FEDERAL LEVELS. IF THE
PRESENT TREND TOWARDS COMPETITIVE RESTRUCTURING OF THE ELECTRIC INDUSTRY IS
REVERSED, DISCONTINUED OR DELAYED, OUR BUSINESS PROSPECTS AND FINANCIAL
CONDITION COULD BE MATERIALLY ADVERSELY AFFECTED.
The regulatory environment applicable to the power generation industry has
recently been undergoing substantial changes, on both the federal and state
level. These changes have significantly affected the nature of the industry and
the manner in which its participants conduct their business. Continued
uncertainty and future changes will also affect the way we conduct business.
Moreover, existing statutes and regulations may be revised or reinterpreted,
new laws and regulations may be adopted or become applicable to us or our
facilities, and future changes in laws and regulations may have an effect on
our business in ways that we cannot predict.
Some restructured markets have recently experienced supply problems and
price volatility. These supply problems and this price volatility have been the
subject of a significant amount of press coverage, much of which has been
critical of restructuring initiatives. In some of these markets, government
agencies and other interested parties have made proposals to delay market
restructuring or even re-regulate areas of these markets that have previously
been deregulated. In California, legislation has been passed placing a
moratorium on the sale of generation plants by public utilities regulated by
the California Public Utilities Commission. In June 2001, the FERC instituted a
series of price controls designed to mitigate (or cap) prices in the entire
western U.S. as a result of the California energy crisis. These price controls
have had the effect of significantly lowering spot and forward energy prices in
the western market. Other proposals to re-regulate our industry may be made,
and legislative or other attention to the electric power restructuring process
may cause the process to be delayed, discontinued or reversed in the states in
which we currently, or may in the future, operate. If the current trend towards
competitive restructuring of the wholesale and retail power markets is delayed,
discontinued or reversed, our business prospects and financial condition could
be materially adversely affected.
In June 2001, the Montana Public Service Commission, or MPSC, issued an
order (the MPSC Order) in which it found that Montana Power must continue to
provide electric service to its customers at tariffed rates until its
transition plan under the Montana Electricity Utility Industry Restructuring
and Customer Choice Act is finally approved, and that purchasers of generating
assets from Montana Power must provide electricity to meet Montana Power's full
load requirements at prices to Montana Power that reflect costs calculated as
if the generation assets had not been sold. PPL Montana purchased Montana
Power's interest in two coal-fired plants and 11 hydroelectric units in 1999.
In July 2001, PPL Montana filed a complaint against the MPSC with the U.S.
District Court in Helena, Montana, challenging the MPSC Order. In its
complaint, PPL Montana asserted, among other things, that the Federal Power Act
preempts states from exercising regulatory authority over sale of electricity
in wholesale markets, and requested the court to declare the MPSC action
preempted, unconstitutional
19
and void. In addition, the complaint requested that the MPSC be enjoined from
seeking to exercise any authority, control or regulation of wholesale sales
from PPL Montana's generating assets. At this time, we cannot predict the
outcome of the proceedings related to the MPSC Order.
WE MAY BE ADVERSELY AFFECTED BY LEGAL PROCEEDINGS ARISING OUT OF THE
ELECTRICITY SUPPLY SITUATION IN CALIFORNIA AND OTHER WESTERN STATES.
Litigation arising out of the California electricity supply situation has
been filed with the FERC and in California courts against sellers of energy to
the California ISO. The plaintiffs and intervenors in these proceedings allege
abuse of market power, manipulation of market prices, unfair trade practices
and violations of state antitrust laws, 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 attorney's fees. Certain of our subsidiaries have intervened
in the FERC proceedings in order to protect their interests, but have not been
named as defendants in any of the court actions. In addition, attorneys general
in several western states, including California, have begun investigations
related to the electricity supply situation in California and other western
states. The FERC has determined that all sellers of energy in the California
markets, including our subsidiaries, should be subject to refund liability for
the period beginning October 2, 2000 through June 20, 2001 and has initiated an
evidentiary hearing concerning refund amounts. The FERC also is considering
whether to order refunds for sales made in the Pacific Northwest, including
sales made by our subsidiaries. The FERC Administrative Law Judge assigned to
this proceeding has recommended that no refunds be ordered for sales into the
Pacific Northwest. The FERC presently is considering this recommendation. We
cannot predict whether or the extent to which any of our subsidiaries will be
the target of any governmental investigation or named in these lawsuits, refund
proceedings or other lawsuits, the outcome of any such proceedings or whether
the ultimate impact on us of the electricity supply situation in California and
other western states will be material.
OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND THE COSTS
OF COMPLIANCE WITH NEW ENVIRONMENTAL LAWS COULD ADVERSELY AFFECT OUR
PROFITABILITY.
Our operations are subject to extensive federal, state, local and foreign
statutes, rules and regulations relating to environmental protection. To comply
with these legal requirements, we must spend significant sums on environmental
monitoring, pollution control and emission fees. We may be exposed to
compliance risks from development projects, as well as from plants that we have
acquired. Our failure to comply with environmental laws may result in the
assessment of civil or criminal liability and fines against us by regulatory
authorities. With the trend toward stricter standards, greater regulation, more
extensive permitting requirements and an increase in the number and types of
assets operated by us subject to environmental regulation, we expect our
environmental expenditures to be substantial in the future.
New environmental laws and regulations affecting our operations may be
adopted, and new interpretations of existing laws and regulations could be
adopted or become applicable to us or our facilities. For example, the laws
governing air emissions from coal-burning plants are being re-interpreted by
federal and state authorities. These re-interpretations could result in the
imposition of substantially more stringent limitations on these emissions than
those currently in effect. Our compliance strategy, although reasonably based
on the information available to us today, may not successfully address the
relevant standards and interpretations of the future.
For example, the Environmental Protection Agency, or EPA, has initiated
enforcement actions against several utilities, asserting that over a period of
years older, coal-fired power plants operated by those utilities have been
modified in ways that subject them to more stringent "New Source" requirements
under the Clean Air Act Amendments of 1990, or Clean Air Act. The EPA regional
offices that regulate plants in Pennsylvania (Region III) and Montana (Region
VIII) have indicated an intention to issue information requests to all
utilities in their jurisdictions and the Region VIII Office has issued such a
request to PPL Montana's Corette plant. Should the EPA or a state environmental
agency commence one or more enforcement actions against affiliates of PPL
Energy Supply, compliance with any such enforcement actions could result in
additional capital and operating expenses in amounts which are not now
determinable, but which could be significant.
Most of our contracts with customers do not permit us to recover capital
costs incurred by us to comply with new environmental regulations. As a result,
these costs could adversely affect our profitability.
20
In addition, we may be responsible for any on-site liabilities associated
with the environmental condition of our power generation facilities and natural
gas assets which we have acquired or developed, regardless of when the
liabilities arose and whether they are known or unknown.
In connection with certain acquisitions and sales of assets, we may obtain,
or be required to provide, indemnification against certain environmental
liabilities. The incurrence of a material liability, or the failure of the
other party to meet its indemnification obligations to us, could have a
material adverse effect on our operations and financial condition.
We may not be able to obtain or maintain all required environmental
regulatory approvals. If there is a delay in obtaining any required
environmental regulatory approval or if we fail to obtain, maintain or comply
with any such approval, operations at our affected facilities could be halted
or subjected to additional costs. Further, at some of our older facilities it
may be uneconomical for us to install the necessary equipment, which may cause
us to shut down those generation units.
OUR BUSINESS DEVELOPMENT ACTIVITIES MAY NOT BE SUCCESSFUL AND OUR PROJECTS
UNDER CONSTRUCTION MAY NOT COMMENCE OPERATION AS SCHEDULED.
Our business involves numerous risks relating to the acquisition,
development and construction of power plants and facilities. These activities
can require us to expend significant sums for preliminary engineering,
permitting, fuel supply, resource exploration, legal and other expenses in
preparation for competitive bids which we may not win or before it can be
established whether a project is feasible, economically attractive or capable
of being financed. Our success in developing a particular project is contingent
upon, among other things, negotiation of satisfactory engineering,
construction, fuel supply and power sales contracts, receipt of required
governmental permits and timely implementation and satisfactory completion of
construction. We may be unsuccessful in accomplishing any of these matters or
in doing so on a timely basis.
Currently, we have power plants with 4,605 MW of generation capacity under
development or construction and we intend to pursue the expansion of existing
plants and the acquisition or development of new generation capacity. Our
completion of these facilities without delays or cost overruns is subject to
substantial risks, including:
. changes in market prices;
. issues relating to obtaining permits and approvals and complying with
other regulatory matters;
. availability and timely delivery of gas turbine generators and other
equipment;
. unforeseen engineering problems;
. shortages and inconsistent quality of equipment, material and labor;
. work stoppages;
. adverse weather conditions;
. environmental and geological conditions; and
. unanticipated cost increases,
any of which could give rise to delays, cost overruns or the termination of
expansion, construction or development.
The process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated, expensive and lengthy, often
taking more than one year, and is subject to significant uncertainties. In
addition, construction delays and contractor performance shortfalls can result
in the loss of revenues and adversely affect our results of operations. The
failure to complete construction according to specifications can result in
liabilities, reduced plant efficiency, higher operating costs and reduced
earnings. If we were unable to complete the development of a facility, we would
generally not be able to recover our investment in the project. We cannot
assure you that we will be successful in the development or construction of
power generation facilities in the future.
21
OUR INVESTMENTS AND PROJECTS LOCATED OUTSIDE OF THE UNITED STATES EXPOSE US
TO RISKS RELATED TO LAWS OF OTHER COUNTRIES, TAXES, ECONOMIC CONDITIONS,
FLUCTUATIONS IN CURRENCY RATES, POLITICAL CONDITIONS AND POLICIES OF FOREIGN
GOVERNMENTS. THESE RISKS MAY DELAY OR REDUCE OUR REALIZATION OF VALUE FROM
OUR INTERNATIONAL PROJECTS.
We have operations outside of the United States. In 2000, we derived
approximately 14% of our net income from our foreign operations. The
acquisition, financing, development and operation of projects outside the
United States entail significant political and financial risks, which vary by
country, including:
. changes in foreign laws or regulations relating to foreign operations,
including tax laws and regulations;
. changes in United States laws related to foreign operations, including
tax laws and regulations;
. changes in government policies, personnel or approval requirements;
. changes in general economic conditions affecting each country;
. changes in labor relations in foreign operations;
. limitations on foreign investment or ownership of projects and returns
or distributions to foreign investors;
. limitations on ability of foreign companies to borrow money from foreign
lenders and lack of local capital or loans;
. fluctuations in currency exchange rates and difficulty in converting our
foreign funds to U.S. dollars or moving funds out of the country in
which the funds were earned;
. limitations on ability to import or export property and equipment;
. compliance with United States foreign corrupt practices laws;
. political instability and civil unrest; and
. expropriation and confiscation of assets and facilities.
Our international operations are subject to regulation by various foreign
governments and regulatory authorities. The laws and regulations of some
countries may limit our ability to hold a majority interest in some of the
projects that we may develop or acquire, thus limiting our ability to control
the development, construction and operation of those projects. In addition, the
legal environment in foreign countries in which we currently own assets or
projects or may develop projects in the future could make it more difficult for
us to enforce our rights under agreements relating to such projects. Our
international projects may also be subject to risks of being delayed, suspended
or terminated by the applicable foreign governments or may be subject to risks
of contract invalidation by commercial or governmental entities.
Despite contractual protections we have against many of these risks for our
international operations or potential investments in the future, our actual
results and the value of our investment may be adversely affected by the
occurrence of any of these events.
Risk from fluctuations in currency exchange rates can arise when our foreign
subsidiaries expend or borrow funds in one type of currency but receive revenue
in another. In such cases, an adverse change in exchange rates can reduce our
ability to meet expenses, including debt service obligations. Foreign currency
risk can also arise when the revenues received by our foreign subsidiaries are
not in U.S. dollars. In such cases, a strengthening of the U.S. dollar could
reduce the amount of cash and income we receive from these foreign
subsidiaries. While we believe we have hedges and contracts in place to
mitigate our most significant foreign currency exchange risks, we have some
exposures that are not hedged.
RISKS RELATED TO OUR CORPORATE AND FINANCIAL STRUCTURE
OUR RESULTS DEPEND ON THE PERFORMANCE OF OUR SUBSIDIARIES AND AFFILIATES,
SOME OF WHICH WE DO NOT CONTROL.
We are a holding company and conduct our operations primarily through
wholly-owned subsidiaries, and substantially all of our consolidated assets are
held by these subsidiaries. Accordingly, our cash flow and our ability to meet
our obligations under the new notes are largely dependent upon the earnings of
our subsidiaries
22
and the distribution or other payment of such earnings to us in the form of
dividends or loans or advances and repayment of loans or advances from us. The
subsidiaries are separate and distinct legal entities and have no obligation to
pay any amounts due on the new notes or to make any funds available for such
payment.
Because we are a holding company, our obligations under the new notes will
be effectively subordinated to all existing and future liabilities of our
subsidiaries. Therefore, our rights and the rights of our creditors, including
the rights of the holders of the new notes, to participate in the assets of any
subsidiary in the event that such a subsidiary is liquidated or reorganized
will be subject to the prior claims of such subsidiary's creditors. To the
extent that we may be a creditor with recognized claims against any such
subsidiary, our claims would still be effectively subordinated to any security
interest in, or mortgages or other liens on, the assets of such subsidiary and
would be subordinated to any indebtedness or other liabilities of such
subsidiary senior to that held by us. Although certain agreements to which we
and our subsidiaries are parties limit the incurrence of additional
indebtedness, we and our subsidiaries retain the ability to incur substantial
additional indebtedness and other liabilities.
Two of our major affiliates, WPDL and WPDH, are not subject to our control
of management and policies to the same extent as our consolidated subsidiaries.
We and Mirant Corporation share control of WPDL, which owns Hyder, Limited. We
also jointly control WPDH, which owns Western Power Distribution (South West)
plc, which we refer to as WPD (South West) and Western Power Distribution
(South Wales) plc, which we refer to as WPD South Wales, each a British
regional electric utility. We account for these investments using the equity
method of accounting. These affiliates contributed approximately 11.5% of our
income from continuing operations in 2000.
We have limited control over the development, construction, acquisition or
operation of some project investments and joint ventures where we beneficially
own less than 50% of the ownership interests. We seek to exert a degree of
influence with respect to the management and operation of projects in which we
own less than 50% of the ownership interests by negotiating to obtain positions
on management committees or to receive certain limited governance rights such
as rights to veto significant actions. However, we may not always succeed in
such negotiations. We may be dependent on our co-venturers to construct and
operate such projects. Our co-venturers may not have the level of experience,
technical expertise, human resources management and other attributes necessary
to successfully construct and operate these projects. The approval of
co-venturers also may be required for us to receive distributions of funds from
projects or to transfer our interest in projects.
The debt agreements of some of our subsidiaries and affiliates restrict
their ability to pay dividends, make distributions or otherwise transfer funds
to us prior to the payment of other obligations, including operating expenses,
debt service and reserves. Further, if we elect to receive distributions of
earnings from our foreign operations, we may incur United States taxes, net of
any available foreign tax credits, on such amounts. Dividend payments from our
international projects to us are, in some countries, also subject to
withholding taxes.
WE WILL LIKELY NEED SIGNIFICANT ADDITIONAL FINANCING TO PURSUE OUR BUSINESS
STRATEGY.
Our business strategy anticipates significant future acquisitions and
development of additional generation facilities. We are continually reviewing
potential acquisitions and development projects and may enter into significant
acquisitions or development projects in the future. Any acquisition or
development project will likely require access to substantial capital from
outside sources on acceptable terms. We can give no assurance that we will
obtain the substantial debt and equity capital required to invest in, acquire
and develop new generation projects, to refinance existing projects or to
complete projects under construction. We may also need external financing to
fund capital expenditures, including capital expenditures necessary to comply
with environmental regulations or other regulatory requirements.
Our ability to arrange financing and our cost of capital are dependent on
numerous factors, including:
. general economic conditions, including the conditions in the energy
industry;
23
. credit availability from banks and other financial institutions;
. market prices for electricity and fuels;
. our capital structure and the maintenance of acceptable credit ratings;
. our financial performance;
. the success of current projects and the perceived quality of new
projects; and
. provisions of relevant tax and securities laws.
In the past, the capital needs of our subsidiaries have been supported
primarily by PPL Corporation. PPL Corporation has also periodically provided
credit support to us and certain of our subsidiaries in the form of guarantees,
letters of credit and funding commitments. Future indebtedness may include
terms that are more restrictive or burdensome than those of our (or our
subsidiaries') current indebtedness and other obligations to PPL Corporation.
As a result, we may not be able to obtain third-party financing on terms that
are as favorable as we have experienced in the past, or at all. In addition, in
the future, we may be required to provide guarantees and other credit support
of our subsidiaries' obligations on terms that are less favorable than those
available to PPL Corporation.
Inability to obtain sufficient financing on terms that are acceptable to us
will adversely affect our ability to pursue acquisition and development
opportunities and fund capital expenditures. This would have a material adverse
effect on our business.
OUR CONTROLLING STOCKHOLDER IS NOT OBLIGATED TO PROVIDE US WITH FUTURE EQUITY
FUNDING AND POTENTIAL CONFLICTS OF INTEREST WITH OUR CONTROLLING STOCKHOLDER
MAY BE RESOLVED IN A MANNER THAT IS ADVERSE TO US.
We are an indirect wholly-owned subsidiary of PPL Corporation. Since our
formation, PPL Corporation has indirectly provided all of our equity funding.
PPL Corporation is not obligated to provide any loans, further equity
contributions or other funding to us.
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 note holders as our 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 note
holders, including through the payment of dividends to our parent, PPL Energy
Funding.
In the future, PPL Corporation or its subsidiaries may compete with us for
business opportunities.
RISKS RELATED TO THE EXCHANGE OFFER, TO THE MARKET FOR THE NEW NOTES AND TO
PROJECTIONS THAT MAY NOT BE INDICATIVE OF FUTURE PERFORMANCE
IF YOU FAIL TO EXCHANGE OLD NOTES, THEY WILL REMAIN SUBJECT TO TRANSFER
RESTRICTIONS.
Any old notes that remain outstanding after this exchange offer will
continue to be subject to restrictions on their transfer. After this exchange
offer, holders of old notes will not (with limited exceptions) have any further
rights to have their old notes registered under the Securities Act. Any market
for old notes that are not exchanged could be adversely affected by the
conclusion of this exchange offer and you may be unable to sell your old notes.
LATE DELIVERIES OF OLD NOTES AND OTHER REQUIRED DOCUMENTS COULD PREVENT A
HOLDER FROM EXCHANGING ITS OLD NOTES.
Noteholders are responsible for complying with all exchange offer
procedures. Issuance of new notes in exchange for old notes will only occur
upon completion of the procedures described in this prospectus under the
24
heading "The Exchange Offer". Therefore, holders of old notes who wish to
exchange them for new notes should allow sufficient time for timely completion
of the exchange procedure. Neither we nor the exchange agent are obligated to
notify you of any failure to follow the proper procedure.
IF YOU ARE A BROKER-DEALER, YOUR ABILITY TO TRANSFER THE NEW NOTES MAY BE
RESTRICTED.
A broker-dealer that purchased old notes for its own account as part of
market-making or trading activities must deliver a prospectus when it sells the
new notes. Our obligation to make this prospectus available to broker-dealers
is limited. Consequently, we cannot guarantee that a proper prospectus will be
available to broker-dealers wishing to resell their new notes.
THERE IS NO EXISTING MARKET FOR THE NEW NOTES AND WE CANNOT ASSURE YOU THAT
AN ACTIVE TRADING MARKET WILL DEVELOP.
There is no existing market for the new notes and we do not intend to apply
for listing of the new notes on any securities exchange. There can be no
assurances as to the liquidity of any market that may develop for the new
notes, the ability of noteholders to sell their new notes or the price at which
the noteholders will be able to sell their new notes. Future trading prices of
the new notes will depend on many factors including, among other things,
prevailing interest rates, our operating results and the market for similar
securities. If a market for the new notes does not develop, purchasers may be
unable to resell the new notes for an extended period of time. Consequently, a
noteholder may not be able to liquidate its investment readily.
OUR ACTUAL FUTURE PERFORMANCE MAY NOT MEET PROJECTIONS.
The projections contained in the Summary Independent Technical Review in
Annex A of this prospectus are predicated upon certain assumptions and
forecasts of our major operating companies' revenue generation capacity and the
costs associated therewith. Stone & Webster Consultants has reviewed the
technical parameters of our domestic and international generation facilities,
our international transmission and distribution assets (except for the assets
of WPDL and WPDH), the operations and maintenance budgets of our facilities and
the related assumptions and forecasts contained therein based on a review of
certain technical, environmental, economic and permitting aspects of the
facilities. The Summary Independent Technical Review contains a discussion of
the principal assumptions and considerations utilized in preparing the
projected operating and financial results, which prospective investors should
review carefully. The assumptions made with respect to future market prices for
energy in our domestic markets are based upon a market analysis prepared by ICF
Resources, Inc. and attached as Annex B to this prospectus. See "Annex
A--Summary Independent Technical Review" and "Annex B--Independent Market
Consultant's Report." Each of the Summary Independent Technical Review and the
Independent Market Consultant's Report contains qualifications about the
information in the respective reports and the circumstances under which Stone &
Webster Consultants and ICF Resources performed their respective analyses.
Potential investors should carefully review these reports as well as the
assumptions and qualifications therein. These assumptions and the other
assumptions upon which the projections are based are inherently subject to
significant uncertainties.
Stone & Webster Consultants prepared the Summary Independent Technical
Review with information that was available as of August 15, 2001, and ICF
Resources prepared the Independent Market Consultant's Report with information
that was available as of June 2001 and information contained in those reports
may only be accurate as of their respective dates. We have not requested, nor
do we intend to request, that either Stone & Webster Consultants or ICF
Resources update their reports with information that is currently available.
Moreover, we do not expect to provide comparable projected information in the
future.
Our independent auditors, PricewaterhouseCoopers LLP, have not examined,
reviewed or compiled the projections and, accordingly, do not express an
opinion or any other form of assurance with respect to them. The report of
PricewaterhouseCoopers LLP included in this prospectus relates to our
historical financial statements for the years ended December 31, 2000, 1999 and
1998. It does not extend to any projected financial data and should not be read
to do so.
25
The projected operating and financial results are not necessarily indicative
of our future performance. No representation is made or intended, nor should
any be inferred, with respect to the likely existence of any particular future
set of facts or circumstances. If actual results are less favorable than those
shown or if the assumptions used in formulating the projections and the
sensitivities included in the projected operating results prove to be
incorrect, our ability to pay our operating expenses and other obligations may
be materially adversely affected. You must make your own independent assessment
of our ability to make payments on the new notes.
26
FORWARD-LOOKING INFORMATION
Certain statements contained in this prospectus, including statements with
respect to future earnings, energy supply and demand, costs, subsidiary
performance, growth, new technology, project development, energy and fuel
prices, strategic initiatives, and generating capacity and performance, are
"forward-looking statements" within the meaning of the federal securities laws.
Although we believe that the expectations and assumptions reflected in these
statements are reasonable, there can be no assurance that these expectations
will prove to have been correct. These forward-looking statements involve a
number of risks and uncertainties, and actual results may differ materially
from the results discussed in the forward-looking statements. In addition to
the specific factors discussed in the "Risk Factors" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
sections herein, the following are among the most important factors that could
cause actual results to differ materially from the forward-looking statements:
. market demand and prices for energy, capacity and fuel;
. weather variations affecting customer energy usage;
. competition in retail and wholesale power markets;
. the effect of any business or industry restructuring;
. profitability and liquidity;
. new accounting requirements or new interpretations or applications of
existing requirements;
. operation of existing facilities and operating costs;
. the development of new projects, markets and technologies;
. the performance of new ventures;
. political, regulatory or economic conditions in countries where we or
our subsidiaries conduct business;
. receipt and renewals of necessary governmental permits and approvals;
. capital markets conditions and decisions regarding our capital structure;
. our or any of our subsidiaries' securities ratings;
. foreign exchange rates;
. commitments and liabilities;
. state and federal regulatory developments;
. new state or federal legislation;
. national or regional economic conditions, including any potential
effects arising from the September 11, 2001 terrorist attacks in New
York City, Washington, D.C. and western Pennsylvania, and any
consequential hostilities;
. environmental conditions and requirements; and
. system conditions and operating costs.
Any such forward-looking statements should be considered in light of such
important factors.
New factors that could cause actual results to differ materially from those
described in forward-looking statements emerge from time to time, and it is not
possible for us to predict all of such factors, or the extent to which any such
factor or combination of factors may cause actual results to differ from those
contained in any forward-looking statement. Any forward-looking statement
speaks only as of the date on which such statement is made, and we do not
undertake any obligation to update the information contained in such statement
to reflect subsequent developments or information.
27
USE OF PROCEEDS
The exchange offer is intended to satisfy some of our obligations under the
registration rights agreement. We will not receive any cash proceeds from the
issuance of the new notes in the exchange offer. In exchange for issuing the
new notes as described in this prospectus, we will receive an equal principal
amount of old notes, which will be canceled.
The net proceeds that we received from the sale of the old notes are being
used for general corporate purposes, including funding our growth strategy and
to provide working capital. Until such time as the funds are used as described
above, they may be invested in or used to make demand loans to affiliates at
market-based rates.
CAPITALIZATION
The following table describes our actual consolidated capitalization as of
September 30, 2001, and our pro forma consolidated capitalization adjusted to
reflect the receipt of net proceeds of $489 million from the issuance and sale
of the old notes (after discounts and commissions and estimated offering and
exchange offering expenses). You should read the information in this table
together with our consolidated financial statements and the related notes and
the "Selected Financial Information and Operating Data," and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere in this prospectus .
AS OF SEPTEMBER 30,
2001
---------------------
AS
ACTUAL ADJUSTED
------ --------
(MILLIONS OF DOLLARS)
Cash and cash equivalents............ $ 372 $ 861
====== ======
Short-term debt...................... $ 109 $ 109
Current portion of long-term debt.... 32 32
Short-term debt payable to affiliates - -
------ ------
Total short-term debt............. 141 141
------ ------
Long-term debt....................... 201 201
Senior notes......................... -- 500
------ ------
Total long-term debt.............. 201 701
------ ------
Member's equity...................... 5,594 5,594
------ ------
Total capitalization.............. $5,936 $6,436
====== ======
28
SELECTED FINANCIAL INFORMATION AND OPERATING DATA
The following tables present our selected consolidated financial information
and operating data. The information set forth below should be read together
with "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and our historical consolidated financial statements and the
notes to those statements included in this prospectus. The historical financial
information may not be indicative of our future performance and does not
reflect what our financial position and results of operations would have been
had we operated as a separate, stand-alone entity during the periods presented.
NINE MONTHS ENDED
SEPTEMBER 30, YEARS ENDED DECEMBER 31,
---------------------- -------------------------------------------
2001 2000 2000 1999 1998 1997 1996
------- --------- ------- --------- ----- ----- --------
(MILLIONS OF DOLLARS, EXCEPT RATIOS AND SALES DATA)
STATEMENT OF INCOME DATA
(FOR THE PERIOD):
Operating revenues....................... $ 3,420 $ 1,972 $ 3,121 $ 974 $ 125 $ 4 $ 6
Operating costs and other expenses, other
than depreciation and amortization..... 2,577 1,681 2,568 1,035 103 18 6
Depreciation and amortization............ 118 50 89 20 1 -- --
Operating income (loss).................. 725 241 464 (81) 21 (14) --
Other income (expense):
Interest expense....................... (35) (86) (127) (52) (25) (11) (2)
Other, net............................. 53 22 34 83 10 8 1
------- --------- ------- --------- ----- ----- --------
Total other income (expense)......... 18 (64) (93) 31 (15) (3) (1)
------- --------- ------- --------- ----- ----- --------
Income (loss) from continuing operations
before income taxes and minority
interest............................... 743 177 371 (50) 6 (17) (1)
Income tax expense (benefit)............. 249 53 125 (29) (6) (2) --
Minority interest........................ 4 4 4 14 -- -- --
------- --------- ------- --------- ----- ----- --------
Net income (loss)........................ $ 490 $ 120 $ 242 $ (35) $ 12 $ (15) $ (1)
BALANCE SHEET DATA
(AT THE END OF THE PERIOD):
Cash and cash equivalents................ $ 372 $ 77 $ 130 $ 82 $ 56 $ 43 $ 11
Property, plant and equipment, net....... 3,507 3,260 3,389 1,235 45 46 49
Investments.............................. 1,801 975 1,118 407 723 409 283
Total assets......................... 8,114 6,317 7,463 2,721 938 533 412
Short-term debt payable to affiliated
companies.............................. -- 1,425 2,120 863 501 218 164
Other short-term debt including current
portion of long-term debt.............. 141 47 203 383 3 -- --
Other long-term debt..................... 201 171 159 33 -- -- --
Total debt........................... 342 1,643 2,482 1,279 504 218 164
Member's equity.......................... 5,594 2,534 2,577 922 297 224 146
STATEMENT OF CASH FLOW DATA
(FOR THE PERIOD):
Net cash provided by (used in) operating
activities............................. $ 354 $ 231 $ 615 $ (249) $ 14 $ (12) $ 8
Net cash used in investing activities.... (521) (406) (1,351) (926) (305) (117) (171)
Net cash provided by financing activities 409 170 784 1,201 304 161 164
OTHER FINANCIAL DATA:
EBITDA/(1)/.............................. $ 892 $ 309 $ 583 $ 8 $ 32 $ (6) $ 1
Ratio of Earnings to Fixed Charges/(2)/.. 8.19/(3)/ /(3)/ 2.99 /(4)/ 1.12 1.76 /(5)/
SALES DATA--MILLIONS OF KWH:
Retail supply--domestic.................. 4,993 9,104 11,861 10,271 -- -- --
Retail delivery--international/(6)/...... 4,433 2,360 3,735 2,942 -- -- --
Wholesale supply--domestic/(7)/.......... 19,890 14,965 23,336 330 -- -- --
Wholesale supply--PPL Electric
Utilities/(8)/......................... 24,314 6,290 13,461 -- -- -- --
(FOOTNOTES ON FOLLOWING PAGE)
29
- --------
/(1) /EBITDA is income (loss) before extraordinary items plus interest expense,
income taxes and depreciation. EBITDA is a measure of financial performance
not defined under generally accepted accounting principles, which you
should not consider in isolation or as a substitute for net income, cash
flows from operations or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of
a company's profitability or liquidity. In addition, EBITDA may not be
comparable to similarly titled measures presented by other companies and
could be misleading because all companies and analyses do not calculate it
in the same fashion.
/(2) /The Ratio of Earnings to Fixed Charges is calculated by dividing earnings
by fixed charges. For this purpose, "earnings" means net income (loss)
before income taxes and before adjustment for minority interests in
consolidated subsidiaries or income (loss) from equity investees, plus
fixed charges, plus amortization of capitalized interest, plus distributed
income of equity investees, less interest capitalized. "Fixed charges"
means interest expense, plus interest capitalized, plus amortization of
debt issuance costs, plus the estimated interest component of rent expense.
/(3) /The Ratio of Earnings to Fixed Charges is calculated for the 12-month
period ending September 30, 2001. This ratio was not calculated for the
12-month period ending September 30, 2000.
/(4) /Earnings did not cover fixed charges by $105 million in 1999, primarily
due to a loss incurred by PPL EnergyPlus, and undistributed earnings of PPL
Global's equity method investments.
/(5) /Earnings did not cover fixed charges by $9 million in 1996, primarily due
to undistributed earnings from PPL Global's equity investments, and losses
incurred by PPL Spectrum, Inc.
/(6) /Includes the delivery of electricity by PPL Global's consolidated
affiliates in Chile, El Salvador, Bolivia and Brazil. Sales data does not
include sales in the United Kingdom, since these investments are accounted
for under the equity method.
/(7) /The year 2000 figure includes the wholesales sales of PPL Montana and PPL
Maine, and the sales of PPL EnergyPlus from July 1, 2000 to December 31,
2000, excluding sales by PPL EnergyPlus to PPL Electric Utilities to meet
its obligations as a provider of last resort.
/(8) /Sales by PPL EnergyPlus to PPL Electric Utilities to meet its obligations
as a provider of last resort.
30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion should be read in conjunction with "Risk Factors,"
"Selected Financial Information and Operating Data" and the Financial
Statements and notes thereto, included elsewhere in this prospectus. See Note 1
to the December 31, 2000 Financial Statements for a discussion of the entities
that comprise PPL Energy Supply and the use of predecessor business data to
prepare our financial statements.
CORPORATE REALIGNMENT
On July 1, 2000, PPL Corporation and PPL Electric Utilities completed a
corporate realignment in order to effectively separate PPL Electric Utilities'
regulated transmission and distribution operations from its generation
operations and to better position the companies and their affiliates in the new
competitive marketplace. The corporate realignment included the following key
features:
. PPL Electric Utilities contributed its generation and certain other
related assets, along with associated liabilities, to new competitive
generation subsidiaries of PPL Generation. In connection with the
contribution, PPL Energy Funding, the parent company of PPL Generation,
assumed $670 million aggregate principal amount of PPL Electric
Utilities' debt issued to affiliated companies.
. PPL Electric Utilities also contributed assets associated with its
wholesale energy marketing activities, along with associated
liabilities, to its wholly-owned subsidiary, PPL EnergyPlus, and
contributed its interest in PPL EnergyPlus to PPL Energy Funding.
. PPL Electric Utilities distributed in a tax-free spin-off all of the
outstanding shares of stock of PPL Energy Funding to PPL Corporation,
which resulted in PPL Energy Funding becoming a wholly-owned subsidiary
of PPL Corporation.
. PPL Corporation's unregulated power subsidiary, PPL Global, also
transferred its U.S. electric generation subsidiaries to PPL Generation.
. PPL Electric Utilities entered into agreements with PPL EnergyPlus for
the purchase of electricity to meet all of PPL Electric Utilities'
requirements through 2001 as a PLR for customers who have not selected
an alternative supplier under the Customer Choice Act and its wholesale
contractual obligations to certain municipalities.
As a result of the corporate realignment:
. PPL Generation's principal business is owning and operating U.S.
generation facilities through various subsidiaries;
. PPL EnergyPlus' principal business is competitive wholesale and retail
energy marketing;
. PPL Global's principal businesses are the acquisition and development of
both U.S. and international energy projects, and ownership and operation
of international energy projects; and
. PPL Electric Utilities' principal businesses are the regulated
transmission and distribution of electricity to serve retail customers
in its franchised territory in eastern and central Pennsylvania, and the
supply of electricity to retail customers in that territory as a PLR.
Other subsidiaries of PPL Corporation are generally aligned in the new
corporate structure according to their principal business functions.
31
The corporate realignment followed receipt of various regulatory approvals,
including approvals from the PUC, the FERC, the NRC, and the Internal Revenue
Service, or the IRS.
On May 31, 2001, PPL Energy Funding contributed its interests in PPL
Generation, PPL EnergyPlus and PPL Global to us. We serve as the parent company
for substantially all of PPL Corporation's competitive businesses.
Our financial statements include financial information from our
predecessors. The financial information for such entities has been combined
together as one collective predecessor for purposes of satisfying the SEC's
financial statement requirements, based on formation or acquisition dates of
the respective businesses and assets. Certain of our assets were not operated
as discrete businesses, and as a result, performance for prior years and
historical predecessor financial information may not be indicative of our
present or future performance. See Note 1 to the December 31, 2000 Financial
Statements for a discussion of the predecessor entities that comprise PPL
Energy Supply.
RESULTS OF OPERATIONS
The Consolidated Statement of Income reflects the results of past operations
and is not intended as any indication of the results of future operations.
Future results of operations will necessarily be affected by various and
diverse factors and developments. Furthermore, because results for interim
periods can be disproportionately influenced by various factors and
developments and by seasonal variations, the results of operations for interim
periods are not necessarily indicative of results or trends for the year.
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2001 AS COMPARED TO THREE AND NINE
MONTHS ENDED SEPTEMBER 30, 2000
The following discussion explains significant changes in principal items on
the Condensed Consolidated Statement of Income included in the Financial
Statements, comparing the three and nine months ended September 30, 2001, to
the comparable periods in 2000. In many cases the reason for the significant
changes for the nine month period is the acquisition of the generation assets
from PPL Electric Utilities in July 2000, as described in the corporate
realignment discussion above. Also, PPL Global acquired 84.7% of CEMAR in June
2000, and fully consolidated its balance sheet accounts on September 30, 2000.
However, the operating results for the first nine months of 2001 include CEMAR,
whereas the results for the same period in 2000 do not.
OPERATING REVENUES
Operating revenues decreased by $47 million and increased by $1,448 million
for the three and nine months ended September 30, 2001, compared to the same
periods in 2000.
WHOLESALE ENERGY MARKETING AND TRADING
The increase (decrease) in revenues from wholesale energy marketing and
trading activities was attributable to the following changes (millions of
dollars):
SEPT. 30, 2001 VS. SEPT. 30, 2000
---------------------------------
THREE MONTHS NINE MONTHS
ENDED ENDED
------------ -----------
Eastern markets........................ $(82) $1,120
Western markets........................ (8) 156
---- ------
$(90) $1,276
==== ======
32
The decrease in eastern markets for the three months ended September 30,
2001 was primarily due to lower gas and oil trading activity, and the
expiration of capacity and energy agreements with JCP&L and BG&E. The decrease
in revenues also reflects lower bilateral/spot market sales of electricity, due
to unplanned outages, creating fewer opportunities to sell forward and less
trading activity, as well as lower spot market prices. These decreases were
offset by a $91 million increase in sales to PPL Electric Utilities to supply
its PLR load. As part of the July 2000 realignment, PPL Electric Utilities
entered into a power sales agreement with PPL EnergyPlus for the purchase of
electricity sufficient to meet its obligations as a PLR for customers who have
not selected an alternative supplier under the Customer Choice Act through
2001. Under the terms of this agreement, PPL EnergyPlus sells this electricity
at the applicable shopping credits authorized by the PUC, plus nuclear
decommissioning costs, less state taxes. PPL Electric Utilities and PPL
EnergyPlus have entered into a long-term contract under which PPL EnergyPlus
has agreed to provide all of PPL Electric Utilities' electricity requirements
from 2002 through 2009. See "Summary--Recent Developments."
Most of the increase in eastern markets for the nine months ended September
30, 2001, was in the first half of 2001, due to increases of $507 million in
wholesale contracts and $622 million in sales to PPL Electric Utilities to meet
its PLR load. These activities were transferred to predecessors of PPL Energy
Supply in the July 2000 corporate realignment. These increases were offset by
the decreases in the third quarter as noted above.
The decrease in the western market for the three month period ended
September 30, 2001 was primarily due to higher wholesale energy prices in the
third quarter of 2000, related to the energy supply shortage in the western
U.S. The increase in the western market for the nine month period was due to
higher wholesale energy prices in the first half of 2001 compared to 2000.
RETAIL ELECTRIC AND GAS
The increase (decrease) in retail revenues from electric and gas operations
was attributable to the following changes (millions of dollars):
SEPT. 30, 2001 VS. SEPT. 30, 2000
--------------------------------
THREE MONTHS NINE MONTHS
ENDED ENDED
------------ -----------
Retail Electric Revenue
Domestic electric supply........ $(67) $(136)
International electric delivery. 34 106
---- -----
(33) (30)
Retail Gas Revenue................. 3 23
---- -----
Retail Revenues--total............. $(30) $ (7)
==== =====
The decrease in retail electric revenue for both periods reflects lower PPL
EnergyPlus domestic retail supply sales, particularly in the second and third
quarters of 2001. This was primarily due to expiration of contracts with
existing customers and an increased emphasis on competing in wholesale markets.
Partially offsetting these decreases where higher international revenues from
electric delivery in both periods, primarily due to the acquisition of CEMAR in
June 2000.
Operating revenues from retail gas operations increased due to higher retail
pricing, reflecting elevated wholesale gas commodity costs.
ENERGY RELATED BUSINESSES
Energy related businesses (which are more fully described in Note 1 to the
December 31, 2000 Financial Statements) contributed $11 million to operating
income but reduced operating income by $4 million for the three
33
months ended September 30, 2001 and 2000, respectively. For the nine months
ended September 30, 2001 and 2000, these businesses contributed a total of $25
million and $18 million to operating income. Positive contributions in 2001
from PPL Global and from PPL EnergyPlus' mechanical contracting and engineering
subsidiaries were partially offset by pre-tax operating losses from PPL
EnergyPlus' synfuel projects. (However, after recording tax credits associated
with synfuel operations, the synfuel projects contributed approximately $12
million to net income for the nine months ended September 30, 2001. See
"--Income Taxes" for further information).
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES
Equity in earnings of unconsolidated affiliates increased by $15 million and
$40 million for the three and nine months ended September 30, 2001 when
compared with the same periods in 2000. This was primarily due to PPL Global's
higher equity earnings from WPDH and other international investments, and the
recording of earnings from its investment in WPDL, which acquired Hyder in
September 2000. Also contributing to the increase were equity earnings
associated with the Griffith Energy Project, in which a PPL Energy Supply
subsidiary has a 50% interest.
OPERATING EXPENSES
FUEL
Fuel costs increased by $228 million for the nine months ended September 30,
2001 compared with the same period in 2000. This increase was primarily due to
the inclusion of PPL Generation subsidiaries as predecessors of PPL Energy
Supply beginning on July 1, 2000.
ENERGY PURCHASES
The increase (decrease) in energy purchases was attributed to the following
changes (million of dollars):
SEPT. 30, 2001 VS. SEPT. 30, 2000
---------------------------------
THREE MONTHS NINE MONTHS
ENDED ENDED
------------ -----------
Domestic
Eastern markets. $(176) $120
Western markets. 29 35
International...... 21 47
----- ----
$(126) $202
===== ====
The decrease in energy purchases in the three month period was primarily due
to lower purchases of electricity and gas in the eastern U.S. markets. This was
attributable to a reduction in volumes, and lower average purchased power
costs. In the nine month period, this decrease was more than offset by the
transfer of the wholesale energy marketing business from PPL Electric Utilities
to PPL EnergyPlus as part of the July 1, 2000 corporate realignment.
Western market purchases increased in both periods because of higher power
costs in 2001 in the western U.S. The increase in international energy
purchases was due to the purchases of CEMAR.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased by $19 million for the
three months ended September 30, 2001 compared with the same period in 2000.
This was primarily due to PPL Global's acquisition of CEMAR in June 2000.
Other operation and maintenance expenses increased by $336 million for the
nine months ended September 30, 2001, compared with the same period in 2000.
The transfer of PPL Electric Utilities' generation
34
assets to PPL Generation on July 1, 2000 was the primary reason for the
increase, along with PPL Global's acquisition of CEMAR. Also contributing to
the increase was PPL Montana's lease of the Colstrip generation facilities in
the first half of 2001, as opposed to depreciating the Colstrip facilities in
the first half of 2000.
DEPRECIATION
Depreciation increased by $9 million and $68 million for the three and nine
months ended September 30, 2001, compared to the same periods in 2000. The
increase in the three month period was due to the inclusion of CEMAR's
transmission, distribution and other assets recorded subsequent to its
acquisition by PPL Global and to SCR technology installed at the Montour plant
during the third quarter 2000 outage. The increase in the nine month period was
primarily due to the inclusion of the generation assets transferred from PPL
Electric Utilities to PPL Generation in the July 1, 2000 corporate realignment,
and the acquisition of the CEMAR assets. These increases were partially offset
by PPL Montana's sale and leaseback of its investment in the Colstrip plant in
July 2000.
OTHER INCOME
Other income of PPL Energy Supply increased by $19 million and $31 million
for the three and nine months ended September 30, 2001, compared to the same
periods in 2000. These increases were primarily due to interest income received
by PPL Investment Corporation from loans made to PPL and its non-PPL Energy
Supply subsidiaries during the period. Also contributing to these increases
were dividends received from PPL Global's investment in CGE in 2001.
INTEREST EXPENSE
Interest expense decreased by $24 million and $51 million for the three and
nine months ended September 30, 2001, compared to the same periods in 2000. The
decreases were primarily related to the contribution to PPL Energy Supply of
PPL Energy Funding's notes receivable from PPL Global, thereby eliminating the
associated intercompany interest expense. The retirement of PPL Montana debt
obligations also contributed to the decrease in the nine month period.
INCOME TAXES
Income taxes increased by $25 million and $196 million for the three and
nine months ended September 30, 2001, compared to the same periods in 2000.
Pre-tax book income was higher in both periods in 2001. The increased income
tax expense for the nine month period was partially offset by an adjustment for
federal synfuel tax credits recognized in the second quarter of 2001, following
an evaluation of the IRS' revenue procedures as they apply to the synfuel
projects.
YEAR ENDED DECEMBER 31, 2000 AS COMPARED TO YEAR ENDED DECEMBER 31, 1999, AND
YEAR ENDED DECEMBER 31, 1999 AS COMPARED TO YEAR ENDED DECEMBER 31, 1998
The following discussion explains significant changes in principal items on
the Consolidated Statement of Income included in the Financial Statements,
comparing 2000 to 1999, and 1999 to 1998. In many cases, the reasons for the
significant changes are the inclusion of additional predecessors of PPL Energy
Supply. The most significant of these, and their timings, are:
. The acquisition of the generation assets from PPL Electric Utilities
in July 2000, as described in the corporate realignment discussion
above;
. The acquisition of the Montana generation assets in December 1999; and
. The consolidation of Empresas Emel, S.A., or Emel, and Electricidad
de Centroamerica, S.A. de C.V., or EC, by PPL Global effective
January 1, 1999.
35
OPERATING REVENUES
Operating revenues increased by $2.15 billion, from $974 million to $3.12
billion, from 1999 to 2000 and by $849 million, from $125 million to $974
million, from 1998 to 1999.
WHOLESALE ENERGY MARKETING AND TRADING
The increase in revenues from wholesale energy marketing and trading
activities was attributable to the following changes (millions of dollars):
2000 VS. 1999 1999 VS. 1998
------------- -------------
Eastern markets $1,364 $37
Western markets 417 9
------ ---
$1,781 $46
====== ===
The increase in wholesale energy marketing revenues in 2000 was primarily
due the corporate realignment in July 2000. As part of the realignment, PPL
Electric Utilities entered into power sales agreements with PPL EnergyPlus for
the purchase of electricity to meet its obligations as a PLR for customers who
have not selected an alternative supplier under the Customer Choice Act. These
purchases, which are part of the eastern market revenues, totaled $540 million
for the six months ended December 31, 2000.
Wholesale marketing revenues in eastern markets also increased by $576
million due to wholesale contracts that were transferred from PPL Electric
Utilities to PPL EnergyPlus effective with the July 1, 2000 realignment.
Western market revenues increased, reflecting a full year of PPL Montana
operation in 2000, as opposed to approximately two weeks in 1999.
Wholesale energy marketing and trading revenues increased by $46 million in
1999 compared with 1998. This increase was due to the inclusion of PPL Montana,
PPL EnergyPlus and PPL Maine as PPL Energy Supply predecessors.
RETAIL ELECTRIC AND GAS
The increase in retail revenues from electric and gas operations was
attributable to the following changes (millions of dollars):
2000 VS. 1999 1999 VS. 1998
------------- -------------
Retail Electric Revenue
Domestic electric supply........ $ 94 $416
International electric delivery. 75 245
---- ----
169 661
Retail Gas Revenue................. 49 --
---- ----
Retail Revenues--total............. $218 $661
==== ====
Operating revenues from retail electric operations increased by $169 million
in 2000 compared with 1999. PPL EnergyPlus provided 15.5% more electricity to
domestic retail customers in 2000 as compared to 1999. Revenues from
international electric delivery were $75 million, or 31%, greater in 2000 as
compared to 1999, due to the acquisition of CEMAR and higher sales volumes in
Chile, El Salvador and Bolivia. Lastly, PPL EnergyPlus' increase in retail gas
revenue in 2000 was related to intensified gas marketing efforts and increased
retail pricing attributable to higher wholesale gas commodity costs.
36
Operating revenues from retail electric operations increased by $661 million
in 1999 compared with 1998. The $416 million increase in domestic electric
supply was due to PPL EnergyPlus' sales as an alternate supplier of electricity
in Pennsylvania. Effective January 1, 1999, customers were allowed to choose
their electricity supplier under the Pennsylvania Customer Choice Act. The $245
million increase in international electric delivery was primarily due to the
consolidation of Emel and EC results, effective January 1, 1999.
ENERGY RELATED BUSINESSES
Energy related businesses (which are more fully described in Note 1 to the
December 31, 2000, Financial Statements) contributed $24 million to the 2000
operating income of PPL Energy Supply, which was an increase of $22 million
from 1999. This net increase was due to increased operating income of the
mechanical contracting and engineering subsidiaries and increased energy
related business by PPL Global affiliates, but was somewhat offset by operating
losses incurred by PPL EnergyPlus' synfuel projects.
Energy related businesses provided $2 million to operating income in 1999,
as compared to breaking even in 1998. This was due to the inclusion of PPL
Global subsidiaries, Emel and EC, as predecessors of PPL Energy Supply
beginning with their January 1, 1999 consolidation, and also due to additional
operating income provided by the mechanical contracting and engineering firms.
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES
Equity in earnings of unconsolidated affiliates increased by $10 million in
2000 as compared to 1999 due to PPL Global's higher equity earnings from WPDH
and the recording of earnings from its investment in WPDL, which acquired Hyder
in September 2000. Equity in earnings of unconsolidated affiliates increased by
$11 million in 1999 as compared to 1998 due to higher equity earnings from WPDH.
OPERATING EXPENSES
FUEL
Fuel costs increased by $267 million in 2000 compared with 1999 due to the
inclusion of PPL Generation subsidiaries as predecessors of PPL Energy Supply
beginning on July 1, 2000, and fuel costs related to PPL Montana's full year of
production in 2000.
ENERGY PURCHASES
The increase in energy purchases was attributable to the following changes
(millions of dollars):
2000 VS. 1999 1999 VS. 1998
------------- -------------
Domestic
Eastern markets. $446 $611
Western markets. 132 1
International...... 46 142
---- ----
$624 $754
==== ====
The increase in energy purchases in 2000 was primarily in the eastern
markets due to the transfer of the wholesale energy marketing business from PPL
Electric Utilities to PPL EnergyPlus as part of the July 1, 2000 realignment.
The western market energy purchase increase reflects a full year of operation
by PPL Montana in 2000 as opposed to approximately two weeks in 1999.
Energy purchases increased by $754 million in 1999 with the inclusion of PPL
EnergyPlus purchases in the eastern market beginning in 1999 and the inclusion
of international energy purchases made by Emel and EC,
37
which were consolidated by PPL Global effective January 1, 1999. The purchases
in 1999 by PPL EnergyPlus, Emel and EC were primarily to serve their retail
customer load. In 1999, PPL EnergyPlus purchased most of its electricity from
PPL Electric Utilities under the terms of a power supply agreement.
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance expenses increased by $425 million in 2000
when compared with 1999. The transfer of PPL Electric Utilities' generation
assets to PPL Generation on July 1, 2000, was the primary reason for the
increase, along with PPL Montana's full year of operation in 2000 compared to
two weeks in 1999, and PPL Global's acquisition of CEMAR in June 2000. These
increases were partially offset by gains on the sale of emission allowances in
2000, which were recorded as reductions in operation and maintenance expense.
Other operation and maintenance expenses increased by $30 million in 1999
compared with 1998. PPL Global's consolidation of Emel and EC, effective
January 1, 1999, was the primary reason for the increase, along with PPL
EnergyPlus' increased sales expenses in marketing retail electricity supply in
Pennsylvania and other states that deregulated energy supply. These increases
were partially offset by gains on the sale of emission allowances in 1999,
which were recorded as reductions in operation and maintenance expense.
TRANSMISSION
Since PPL Energy Supply owns no domestic transmission or distribution
facilities, other than facilities to interconnect its generation with the
electric transmission system, its PPL EnergyPlus, PPL Montana and other PPL
Generation subsidiaries must pay the owners of transmission systems to deliver
the energy these subsidiaries supply to retail and wholesale customers.
Transmission expenses in 2000 were associated with a full year of PPL Montana's
operation, in which $12 million of transmission expenses were incurred, and the
operation of the assets of the other PPL Generation assets subsequent to July
1, 2000, which amounted to $42 million.
DEPRECIATION
Depreciation increased by $69 million in 2000 compared with 1999. About $53
million of the increase was due to the inclusion of the generation assets
transferred from PPL Electric Utilities to PPL Generation. Also, expenses in
2000 include a full year of depreciation related to PPL Montana, as compared to
approximately two weeks of such expenses in 1999. Finally, depreciation of
CEMAR's transmission, distribution and other assets was recorded subsequent to
its acquisition by PPL Global in June 2000.
Depreciation increased by $19 million in 1999 compared with 1998 due to the
consolidation by PPL Global of Emel and EC, effective January 1, 1999. This
depreciation reflects Emel and EC's electricity transmission, distribution and
related assets.
TAXES, OTHER THAN INCOME
Taxes, other than income taxes, increased by $34 million in 2000 compared to
1999. This was due to PPL EnergyPlus' gross receipts tax increase that
corresponds to its increased revenues, real estate taxes associated with the
generation assets acquired on July 1, 2000, increased capital stock tax, and
the inclusion of a full year of PPL Montana's taxes.
The increase of $19 million in taxes, other than income, in 1999 over 1998
was due to PPL EnergyPlus' gross receipts tax increase that corresponds to its
increased revenues.
PROJECT DEVELOPMENT
Project development costs increased $14 million in 2000 over 1999, as PPL
Global increased the number of domestic generation projects it was developing
during this period. There was no significant change in project development
costs between 1999 and 1998.
38
OTHER INCOME
Other income of PPL Energy Supply decreased by $49 million in 2000 from
1999. In 2000, PPL Generation recorded a $12 million loss contingency for an
unasserted claim against the company under the Clean Air Act. Other income in
1999 included PPL Global's share of the gain on the sale of South West
Electricity plc's electrical supply business (which was $78 million pre-U.S.
tax), and a $56 million pre-tax gain on the sale of PPL Electric Utilities'
Sunbury plant that was recorded by predecessors of PPL Energy Supply. These
increases were partially offset by a $51 million write-down of certain of PPL
Global's international investments: WPD, Aguaytia Energy, LLC, or Aguaytia, and
Empresa Electrica Valle Hermosa S.A., or EVH. The net impact of the charges in
2000, compared to the credits to income in 1999, was the primary reason for the
decrease in other income between the periods.
Other income in 1999 increased by $73 million from 1998. In 1998, PPL Global
recorded a $9 million credit for a reduction in the U.K. corporate tax in
connection with its equity investment in WPD. However, there were larger
below-the-line credits to other income in 1999, as noted above.
INTEREST EXPENSE
Interest expense increased by $75 million in 2000 over 1999 due to increased
borrowing by PPL Global and the inclusion of a full year of PPL Montana debt
expense. Interest expense increased by $27 million in 1999 over 1998 due to
increased borrowing by PPL Global.
INCOME TAXES
Income tax expense increased by $154 million in 2000, compared to 1999. This
was primarily due to an increase in pre-tax book income. Income tax expense
decreased by $23 million in 1999 compared to 1998, due to a decrease in pre-tax
book income.
FINANCIAL CONDITION
ENERGY MARKETING AND TRADING ACTIVITIES
PPL Energy Supply, through PPL EnergyPlus, purchases and sells energy at the
wholesale level under FERC market-based tariffs throughout the United States.
PPL EnergyPlus enters into agreements to market energy and capacity from PPL
Generation's generation assets with the expectation of profiting from market
price fluctuations.
If we were unable to deliver firm capacity and energy under these
agreements, then under certain circumstances we would be required to pay
damages. These damages would be based on the difference between the market
price to acquire replacement capacity or energy and the contract price of the
undelivered capacity or energy. Depending on price volatility in the wholesale
energy markets, such damages could be significant. Extreme weather conditions,
unplanned power plant outages, transmission disruptions, non-performance by
counterparties (or their counterparties) with which PPL EnergyPlus has power
contracts, and other factors could affect our ability to meet our firm capacity
or energy obligations, or cause significant increases in the market price of
replacement capacity and energy. Although we attempt to mitigate these risks,
there can be no assurance that we will be able to fully meet our firm
obligations, that we will not be required to pay damages for failure to
perform, or that we will not experience counterparty non-performance in the
future. We attempt to mitigate risks associated with open contract positions by
reserving generation capacity to deliver electricity to satisfy our net firm
sales contracts and, when necessary, by purchasing firm transmission service.
In addition, we adhere to a comprehensive risk management policy and programs,
including established credit policies to evaluate counterparty credit risk.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies and procedures with respect to
39
counterparties (including requirements that counterparties meet certain credit
ratings criteria) and we require other assurances in the form of credit support
or collateral in certain circumstances in order to limit counterparty credit
risk. However, we have concentrations of suppliers and customers in the
electric and natural gas industries, including electric utilities, natural gas
distribution companies and other energy marketing and trading companies. These
concentrations of counterparties may impact our overall exposure to credit
risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions. To
date, we have not experienced any significant losses due to non-performance by
counterparties. However, given the current electric energy situation in
California, we have established an $18 million reserve with respect to certain
sales to the California ISO for which we have not yet been paid. See Note 17 to
the December 31, 2000 Financial Statements, Note 11 to the September 30, 2001
Financial Statements and "Business--Legal Proceedings" for discussions related
to the California energy situation.
On January 1, 1999, our predecessors adopted mark-to-market accounting for
energy contracts executed for trading purposes, in accordance with EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." Under mark-to-market accounting, gains and losses from changes in
market prices on contracts executed for trading purposes are reflected in
current earnings. The earnings effect of mark-to-market accounting was not
significant in 1999. Under EITF 98-10, energy trading activities refer to
energy contracts executed with the objective of generating profits on, or from
exposure to, shifts or changes in market prices. Risk management activities
refer to energy contracts that are designated as (and effective as) hedges of
non-trading activities (i.e., marketing available capacity and energy and
purchasing fuel for consumption). We adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS 138,
effective January 1, 2001. See Note 16 to the December 31, 2000 Financial
Statements and Note 9 to the September 30, 2001 Financial Statements for the
effect of adopting SFAS 133. Under the terms of SFAS 133, PPL Energy Supply
recorded at fair value certain derivative instruments that do not qualify as
hedges. This resulted in a cumulative-effect credit to earnings on January 1,
2001 of $11 million in recognition of these instruments.
The cumulative-effect adjustment in earnings to recognize at fair value all
derivatives that are designated as fair-value hedging instruments and the
cumulative-effect adjustment to recognize the difference between the carrying
values and fair values of related hedged liabilities are insignificant.
MARKET RISK SENSITIVE INSTRUMENTS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We actively manage the market risk inherent in our commodity, debt, foreign
currency and equity positions. Our board of managers has adopted a
comprehensive risk management policy to manage the risk exposures related to
counterparty credit, energy prices, interest rates and foreign currency
exchange rates. Our subsidiary, PPL EnergyPlus, has adopted its own commodity
risk management policy to manage energy prices and related exposures. The PPL
Corporation policy established a Risk Management Committee comprised of certain
senior officers of PPL Energy Supply and PPL Corporation that oversees the risk
management function. Nonetheless, adverse changes in commodity prices, interest
rates, foreign currency exchange rates and equity prices may result in losses
in earnings, cash flows and/or fair values. The forward-looking information
presented below provides only 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 commodity risk management program is designed to manage the risks
associated with market fluctuations in the price of electricity, natural gas,
oil, coal and emission allowances. PPL Corporation's risk management policy and
our risk management programs include risk identification and risk limits
management, with measurement and controls for real-time risk monitoring. In
2000, our predecessors entered into fixed-price
40
forward and option contracts that required physical delivery of the commodity,
exchange-for-physical transactions and over-the-counter contracts (such as swap
agreements where settlement is generally based on the difference between a
fixed and index-based price for the underlying commodity). We have continued to
use such contracts in 2001 and expect to do so in the foreseeable future.
We enter into contracts to hedge the impact of market fluctuations on our
energy-related assets, liabilities and other contractual arrangements. In
addition, we execute these contracts 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.
For our hedge portfolio, a 10% adverse movement in market prices across all
geographic areas and time periods would have decreased the value of our hedge
portfolio by approximately $32 million at September 30, 2001, $292 million at
December 31, 2000, and $87 million at December 31, 1999. However, this would
have been fully offset by an increase in the value of the underlying commodity,
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 power plants. We
estimated that a 10% adverse movement in market prices across all geographic
areas and time periods would have decreased the value of our non-hedge
portfolio by approximately $1 million at September 30, 2001, $6 million at
December 31, 2000, and $1 million at December 31, 1999.
On July 1, 2000, PPL Corporation and PPL Electric Utilities completed a
corporate realignment and transferred generation assets to various PPL Energy
Supply subsidiaries. As part of the realignment, PPL Electric Utilities and PPL
EnergyPlus entered into a power sales agreement under which PPL EnergyPlus
sells PPL Electric Utilities energy, capacity and ancillary services at the
pre-determined rates PPL Electric Utilities is permitted to charge its PLR
customers, to fulfill its PLR obligation through 2001. In June 2001, PPL
EnergyPlus entered into a separate long-term contract with PPL Electric
Utilities to provide all of PPL Electric Utilities' electricity requirements
from 2002 through 2009, at the pre-determined rates PPL Electric Utilities is
permitted to charge its PLR customers. See Note 12 to the September 30, 2001
Financial Statements for additional information.
INTEREST RATE RISK
Some of PPL Energy Supply's predecessors have issued debt to finance their
operations. We have adopted PPL Corporation's interest rate risk management
program, designed to hedge interest rate risk. PPL Corporation will manage
interest rate risk for us by using financial derivative products to adjust the
mix of fixed and floating-rate interest rates in our debt portfolios, adjusting
the duration of its debt portfolios and locking in treasury rates (and interest
rate spreads over treasuries) in anticipation of future financing, when
appropriate. Risk limits under the risk management program are 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.
PPL Corporation will use various risk management instruments to reduce our
exposure to adverse interest rate movements for future anticipated financings.
While we are exposed to changes in the fair value of these instruments, they
are designed such that any economic loss in value should be offset by interest
rate savings at the time the future anticipated financing is completed. At each
of September 30, 2001, December 31, 2000 and December 31, 1999, we had not
entered into any such instruments.
We are also exposed to changes in the fair value of our debt portfolio. We
estimate that our potential exposure to a change in the fair value of our debt
portfolio through a 10% adverse movement in interest rates at December 31, 2000
was $1 million, compared with a negligible amount at December 31, 1999. At
September 30, 2001, we had no such exposure.
41
FOREIGN CURRENCY RISK
We have investments in international energy-related distribution facilities,
and are exposed to foreign currency risk primarily through investments in
affiliates in Latin America and Europe. In addition, we may make purchases of
equipment in currencies other than U.S. dollars. PPL Corporation manages the
foreign currency risk for PPL Energy Supply. We have adopted PPL Corporation's
foreign currency risk management program designed to hedge foreign currency
exposures including firm commitments, recognized assets or liabilities,
forecasted transactions or net investments. During the first quarter of 2001,
we completed the forward purchase of 51 million euros to pay for certain
equipment in 2002 and 2003. The estimated value of these forward purchases as
of September 30, 2001, being the amount we would have to pay to terminate them,
was $2 million.
NUCLEAR DECOMMISSIONING FUND--SECURITIES PRICE RISK
In connection with the corporate realignment, effective July 1, 2000, the
nuclear decommissioning trust funds for the Susquehanna nuclear plant were
transferred from PPL Electric Utilities to our subsidiary, PPL Susquehanna.
PPL Susquehanna maintains trust funds, as required by the NRC, to fund
certain costs of decommissioning the Susquehanna station. At September 30, 2001
and December 31, 2000, these funds were invested primarily in domestic equity
securities and fixed-rate, fixed-income securities and are reflected at fair
value on our Consolidated Balance Sheet. The mix of securities is designed to
provide returns to be used to fund Susquehanna's decommissioning and to
compensate for inflationary increases in decommissioning costs. However, the
equity securities included in the trusts are exposed to price fluctuation in
equity markets, and the values of fixed-rate, fixed-income securities are
exposed to changes in interest rates. PPL Susquehanna actively monitors the
investment performance and periodically reviews asset allocation in accordance
with its nuclear decommissioning trust policy statement. A hypothetical 10%
increase in interest rates and 10% decrease in equity prices would have
resulted in an estimated $26 million reduction in the fair value of the trust
assets at September 30, 2001, an $18 million reduction at December 31, 2000 and
a $19 million reduction at December 31, 1999.
PPL Electric Utilities' 1998 PUC restructuring settlement agreement provides
for the collection of authorized nuclear decommissioning costs through a
competitive transition charge on customer bills, as authorized under the
Customer Choice Act. Additionally, PPL Electric Utilities is permitted to seek
recovery from customers of up to 96% of any increases in these costs. Under the
power supply agreement between PPL Electric Utilities and PPL EnergyPlus, these
revenues are passed on to PPL EnergyPlus. In turn, these revenues are passed on
to PPL Susquehanna under a power supply agreement between PPL EnergyPlus and
PPL Susquehanna. Therefore, our securities price risk is expected to remain
insignificant.
CAPITAL EXPENDITURE REQUIREMENTS
The schedule below shows our current capital expenditure projections for the
years 2001-2005 and actual spending by our predecessors for the year 2000
(millions of dollars).
PPL ENERGY SUPPLY CAPITAL EXPENDITURE REQUIREMENTS
ACTUAL PROJECTED/(1)/
------ ------------------------
2000 2001 2002 2003 2004 2005
------ ---- ---- ---- ---- ----
Construction expenditures/(2)/
Generation facilities/(3)/.............. $221 $387 $826 $473 $118 $107
Environmental........................... 69 69 18 22 57 51
Other................................... 4 49 14 14 13 12
---- ---- ---- ---- ---- ----
Total Construction Expenditures..... 294 505 858 509 188 170
Nuclear fuel............................... 30 59 54 55 57 57
---- ---- ---- ---- ---- ----
Total Capital Expenditures.......... $324 $564 $912 $564 $245 $227
==== ==== ==== ==== ==== ====
42
- --------
/(1)/These capital expenditure estimates include our current projections of
costs associated with environmental and construction expenditures at our
existing facilities and construction expenditures relating to the 4,605 MW
of planned domestic generation projects under development that are
specifically referenced in this prospectus. Expenditures to be funded under
operating leases for simple-cycle peaking turbines and the combined-cycle
facility in Lower Mt. Bethel are included.
/(2)/Construction expenditures include allowance for funds used during
construction and capitalized interest, which are expected to be less than
$11 million in each of the years 2001-2005. This information excludes any
equity investments by PPL Global.
/(3)/Includes the projected development costs for PPL Global's domestic
generation projects. Some of these projects may ultimately be financed by
parties who lease such projects back to us pursuant to leases that are not
capitalized on our financial statements.
Our capital expenditure projections for the years 2001-2005 total about $2.5
billion. Capital expenditure plans are revised from time to time to reflect
changes in conditions.
ACQUISITIONS AND DEVELOPMENT
From time to time we are involved in negotiations with third parties
regarding acquisitions, joint ventures and other arrangements which may or may
not result in definitive agreements. Refer to Note 9 to the December 31, 2000
Financial Statements and Note 6 to the September 30, 2001 Financial Statements
for information regarding recent acquisitions and development activities.
At September 30, 2001, PPL Global had investments in foreign facilities,
including consolidated investments in Emel, EC, CEMAR and others. See Note 3 to
the September 30, 2001 Financial Statements for information on PPL Global's
unconsolidated investments accounted for under the equity method.
At September 30, 2001, PPL Global had domestic generation projects, either
announced or under development, which would provide 4,605 megawatts of
generation. Construction activities were nearly completed on the Griffith and
Wallingford projects, located near Kingman, Arizona and Wallingford,
Connecticut, respectively. These facilities are expected to be operational
during the fourth quarter of 2001, and will add in excess of 500 MW of
generation capacity. PPL Global also is developing projects in Arizona,
Illinois, New York, Pennsylvania and Washington. PPL Global is continuously
reexamining development projects based on market conditions and other factors
to determine whether to proceed with these projects, sell them, cancel them,
expand them, execute tolling agreements, or pursue other opportunities.
Also, in October 2001, PPL Global announced that it was pursuing, in
conjunction with the Long Island Power Authority, the construction of two
simple-cycle generating facilities at Shoreham and Brentwood, both located on
Long Island in New York state. These facilities will be owned and operated by a
PPL Global subsidiary and use LM-6000 combustion turbines to provide a combined
160 megawatts of electricity. These facilities are expected to be in service in
the summer of 2002, pending the completion of definitive agreements.
LIQUIDITY AND CAPITAL RESOURCES
Cash and cash equivalents increased by $247 million more during the nine
months ended September 30, 2001, compared with the nine months ended September
30, 2000. The reasons for this change were:
. A $123 million increase in cash provided by operating activities,
primarily due to the operating results of the Pennsylvania generation
assets following the July 1, 2000 corporate realignment, and receipt of
the $90 million up-front payment by PPL Electric Utilities under the new
PLR contract. These increases were partially offset by changes in
current assets and current liabilities;
. A $115 million increase in cash used in investing activities, primarily
due to the proceeds of PPL Montana's sale and leaseback of the Colstrip
facilities in 2000; and
43
. A $239 million increase in cash provided by net financing activities.
Cash and cash equivalents increased by $22 million more during 2000 compared
with 1999. The reasons for this change were:
. An $864 million increase in cash provided by operating activities in
2000, primarily due to a full year of income from the Montana generation
assets, and the results of the Pennsylvania generation assets following
the July 1, 2000 corporate realignment;
. A $425 million increase in cash used in investing activities, primarily
due to expenditures for property, plant and equipment for the
Pennsylvania and Montana generation assets, and an increase in notes
receivable from affiliated companies; and
. A $417 million decrease in cash provided by financing activities,
primarily due to lower contributions from PPL Energy Funding.
Our assets at September 30, 2001 include $1.4 billion in notes receivable
from affiliated companies, of which $1.1 billion is receivable from PPL Energy
Funding, $151 million from PPL Corporation and $101 million from PPL Gas
Utilities. These receivables bear interest at market rates.
In June 2001, we entered into a $600 million 364-day credit agreement and a
$500 million three-year credit agreement, each of which is with a group of
banks and guaranteed by PPL Corporation. The PPL Corporation guarantee fell
away in connection with our issuance of the old notes described in Note 13 to
the September 30, 2001 Financial Statements. Borrowings under these credit
agreements may be used for general corporate purposes, including providing
liquidity for any future commercial paper program. As of September 30, 2001,
there were no borrowings outstanding under these credit agreements.
Also in June 2001, we executed a 364-day revolving credit agreement with PPL
Capital Funding and PPL Corporation under which we have agreed to lend PPL
Capital Funding up to $800 million in order to enhance liquidity and as a
credit back-stop to PPL Capital Funding's commercial paper programs. PPL
Corporation has guaranteed PPL Capital Funding's obligations under this
agreement. At September 30, 2001, there were no borrowings under this credit
agreement.
Later this year we anticipate establishing a commercial paper program at PPL
Energy Supply that will use the credit agreements as back-up credit support. At
that time, PPL Capital Funding will terminate its commercial paper program and
our credit agreement with PPL Capital Funding will terminate.
PPL Montana has a $100 million three-year credit facility to provide working
capital, and up to $75 million of letters of credit. As of September 30, 2001,
$50 million was outstanding under the credit facility and $25 million of
letters of credit were issued. PPL Montana is required to reimburse the lenders
for any drawings under those letters of credit. PPL Montana has also entered
into a new $150 million 364-day credit facility. As of September 30, 2001, no
borrowings were outstanding under this facility. In the event that PPL Montana
were to draw down under this facility and cause lenders to issue letters of
credit on its behalf, PPL Montana would be required to reimburse the issuing
lenders. PPL Corporation has executed a commitment to the lenders under PPL
Montana's $150 million credit facility that PPL Corporation will provide (or
cause PPL Energy Supply to provide if PPL Energy Supply has an investment grade
rating on its senior unsecured debt) letters of credit at such times and in
such amounts as are necessary to permit PPL Montana to remain in compliance
with its fixed-price forward-energy contracts or its derivative financial
instruments entered into to manage energy price risks, to the extent that PPL
Montana cannot provide such letters of credit under its existing credit
agreements. No such letters of credit have been issued as of September 30, 2001.
In July 2000, PPL Montana completed the sale of its investment in the
Colstrip coal-fired plant to owner lessors, which are leasing the assets back
to PPL Montana under four 36-year operating leases. The proceeds
44
from the sale were approximately $410 million. PPL Montana used these proceeds
to reduce outstanding debt and make distributions to its parent, PPL
Generation. This sale-leaseback was financed with the private issuance of
pass-through certificates due 2020. In April 2001, PPL Montana completed an
exchange of these certificates for registered securities.
In September 2000, a subsidiary of PPL Global entered into a $470 million
lease financing of turbine generators, which in November 2000 was increased to
$550 million to include related equipment. The turbines are being financed
using a leasing structure that eliminates the need for cash outlays during the
turbine manufacturing process. The payment obligations of the PPL Global
subsidiary under this lease financing have been guaranteed by PPL Corporation.
In May 2001, another PPL Global subsidiary entered into an arrangement,
initially for $900 million and increased in July 2001 to $1.06 billion upon
syndication, for the development, construction and operation of several
commercial power generation facilities. Certain obligations of the PPL Global
subsidiary under this financing have been guaranteed by us. In addition, PPL
Corporation had guaranteed our obligations. PPL Corporation's guarantee of our
obligations fell away in connection with our issuance of the old notes
described in Note 13 to the September 30, 2001 Financial Statements.
In the past, PPL Corporation has provided credit support for many of our
subsidiaries in the form of guarantees and letters of credit. In the future, we
expect to provide such support instead of PPL Corporation.
In the first nine months of 2001, our member's equity increased from $2.6
billion to $5.6 billion, primarily due to contributions from our member, PPL
Energy Funding. PPL Energy Funding contributed $920 million of notes and
accounts receivable (primarily due from PPL Global) to PPL Investment
Corporation, our financing subsidiary. This contribution was recorded as
additional member's equity, and reduced our consolidated short-term debt
payable to affiliates. PPL Energy Funding also contributed $1.9 billion in
cash, which we used to further pay down short-term debt payable to our member
and other affiliates of PPL Corporation.
ENVIRONMENTAL MATTERS
See "Business--Regulation--Environmental Matters," "Risk Factors" and Note
13 to the December 31, 2000 Financial Statements and Note 7 to the September
30, 2001 Financial Statements for a discussion of environmental matters.
BRAZILIAN OPERATIONS
PPL Global owns 89.6% of CEMAR, which distributes and sells electricity in
the Brazilian state of Maranhao under a 30-year concession agreement between
the government of Brazil and CEMAR. CEMAR's concession agreement provides for
tariff adjustments to be approved by the Brazilian electricity regulator.
In Brazil, the combined effects of growth in demand, decreased rainfall on
the country's heavily hydroelectric dependent generating capacity and delays in
the development of an attractive regulatory structure necessary to encourage
new non-hydroelectric generation recently have led to shortages of electricity
to meet expected demand in certain regions. As a result, countrywide
electricity rationing has been implemented by the Brazilian government. In
addition, the wholesale energy markets in Brazil have been substantially
disrupted. CEMAR's results of operations, its cash flows, and its ability to
meet its financial obligations could be materially adversely affected by
prolonged energy rationing in Brazil, by the continued disruption in the energy
markets and by related factors associated with the current energy shortage.
CEMAR, along with the other Brazilian distributors, is currently in
discussions with the Brazilian regulators regarding necessary tariff
adjustments to address the current situation, and with the Brazilian
development bank
45
regarding financing solutions to the problem. However, there can be no
assurances that such tariff adjustments will be approved by the regulators or
that such financing will be made available. The ultimate impact on PPL Energy
Supply of the current energy supply situation in Brazil is not now determinable
but could be material.
INCREASING COMPETITION
The electric utility industry has experienced, and will likely continue to
experience, an increase in the level of competition in the energy supply market
at both the state and federal level. We believe that as deregulation of the
energy industry continues and markets are opened to new participants and new
services, competition will continue to be intense. Additionally, competitive
pressures have resulted from technological advances in power generation and
electronic communications, and the energy markets have become more efficient.
See "Business--Competition."
FEDERAL ACTIVITIES
PPL EnergyPlus and certain subsidiaries of PPL Generation also have
authority from the FERC to sell electric energy and capacity at market-based
rates and to sell, assign or transfer transmission rights and associated
ancillary services.
PPL EnergyPlus and certain subsidiaries of PPL Generation also have
authority from the FERC to sell specified ancillary services at market-based
rates in the following markets: NEPOOL; the New York Power Pool, or NYPP; the
market administered by the California ISO; and the PJM.
In July 2001, the FERC issued orders calling for the formation of one
regional transmission organization, or RTO, throughout the Mid-Atlantic region
(PJM), New York and New England. In response, we are taking the position that a
single northeastern RTO is a significant step forward in establishing a
reliable and properly functioning wholesale electricity market in the region.
We strongly support the most comprehensive amalgamation of the existing and
proposed northeast power pools, including the establishment of a single RTO as
well as the elimination of marketplace distinctions and control area
boundaries. The FERC's northeastern RTO proceeding is continuing. See
"Business--Our Selected Markets--Domestic Markets" and "--Regulation" for
additional information.
Some restructed markets have recently experienced supply problems and price
volatility. In some of these markets, government agencies and other interested
parties have made proposals to delay market restructuring or even re-regulate
areas of these markets that have previously been deregulated. In California,
legislation has been passed placing a moratorium on the sale of generation
plants by public utilities regulated by the California Public Utilities
Commission. In June 2001, the FERC instituted a series of price controls
designed to mitigate (or cap) prices in the entire western U.S. as a result of
the California energy crisis. These price controls have had the effect of
significantly lowering spot and forward energy prices in the western market.
Other proposals to re-regulate the energy industry may be made, and legislative
or other actions may cause the electric power restructuring process to be
delayed, discontinued or reversed in the states in which we currently, or may
in the future, operate. If the competitive restructuring of the wholesale and
retail power markets is delayed, discontinued or reversed, PPL Energy Supply's
business prospects and financial condition could be materially adversely
affected.
STATE ACTIVITIES
Refer to Note 15 to the December 31, 2000 Financial Statements regarding PPL
Electric Utilities' transfer of its retail electric marketing function to PPL
EnergyPlus. PPL EnergyPlus has a PUC license to act as a Pennsylvania electric
generation supplier. This license permits PPL EnergyPlus to offer retail
electric supply to participating customers in the service territory of PPL
Electric Utilities and in the service territories of other Pennsylvania
utilities.
PPL EnergyPlus sells energy to industrial and commercial customers in
Pennsylvania, New Jersey, Delaware and Montana. PPL EnergyPlus is also licensed
to sell energy in Maine, Maryland and Massachusetts. See "Business--Regulation"
for additional information.
46
BUSINESS
We are a growth-oriented energy company engaged in electric power generation
and marketing primarily in the northeastern and western United States and in
the delivery of electricity abroad.
. We own or control approximately 9,762 MW of electric power generation
capacity and we intend to continue to acquire and develop new, low-cost
and efficient electric power generation facilities generally in our key
northeastern and western markets. In addition, we are constructing or
have announced the development of new electric power projects in
Arizona, Connecticut, Illinois, New York, Pennsylvania and Washington
representing an additional 4,605 MW of power generation capacity.
. We market wholesale or retail energy in 42 states and Canada, deliver
electricity to approximately 4 million customers in the United Kingdom
and Latin America and provide energy-related services to businesses in
the mid-Atlantic and northeastern United States.
Our generation assets are managed as an integrated portfolio, with our
generation operations coordinating with our marketing, trading and risk
management activities.
ORGANIZATIONAL STRUCTURE. We are a Delaware limited liability company and an
indirect, wholly-owned subsidiary of PPL Corporation. PPL Corporation is a
diversified energy and utility holding company headquartered in Allentown,
Pennsylvania. We were formed in November 2000 to serve as the holding company
for PPL Corporation's competitive businesses. See Note 2 to our December 31,
2000 Financial Statements included in this prospectus for financial information
about our Supply and Development segments.
We operate our businesses through principal operating subsidiaries which
include:
. PPL GENERATION, which serves as the holding company for our generation
businesses in the United States. PPL Generation currently owns or
controls a portfolio of domestic power generation assets with a total
capacity of 9,762 MW. These power plants are located in Pennsylvania
(8,509 MW), Montana (1,157 MW) and Maine (96 MW) and use
well-diversified fuel sources including coal, nuclear, natural gas, oil
and hydro. Our Pennsylvania generation assets consist primarily of
low-cost, baseload facilities and are located in the PJM.
. PPL ENERGYPLUS, which markets or brokers electricity produced by PPL
Generation, along with purchased power and natural gas, in wholesale and
deregulated retail markets, primarily in the northeastern and western
United States. In addition, PPL EnergyPlus sells electricity, natural
gas and energy services to retail customers in competitive markets in
Pennsylvania, New Jersey, Maine, Montana and Delaware. During 2000, PPL
EnergyPlus purchased 28.2 billion kWh and had 31.0 billion kWh in energy
sales, excluding sales to PPL Electric Utilities. Under two generation
supply agreements with PPL Electric Utilities which extend through 2009,
PPL EnergyPlus sells electricity to PPL Electric Utilities. PPL
EnergyPlus supplies the electricity to meet PPL Electric Utilities' PLR
obligation to serve electric customers who have not selected an
alternative supplier under the Customer Choice Act, as well as PPL
Electric Utilities' contractual obligations to certain municipalities.
We estimate that approximately 60% of the electricity produced through
2009 by PPL Generation's existing facilities and projects that have been
announced or are currently under development will be sold to PPL
Electric Utilities under these two supply agreements. PPL EnergyPlus
also provides energy-related products and services, such as engineering
and mechanical contracting, construction and maintenance services, to
commercial and industrial customers.
. PPL GLOBAL, which is our development company, acquires and develops U.S.
generation projects. When these U.S. generation projects become
operational, PPL Generation will operate them as part of our integrated
portfolio. PPL Global also acquires, develops, owns and operates
international energy
47
projects that are primarily focused on the distribution of electricity.
PPL Global currently owns and operates electricity delivery businesses
primarily in the United Kingdom and Latin America.
BACKGROUND
PPL Corporation's regulated electric utility subsidiary, PPL Electric
Utilities, provides electricity delivery and supply service to approximately
1.3 million customers in eastern and central Pennsylvania. Until June 30, 2000,
PPL Electric Utilities operated as a vertically-integrated electric utility
that generated, transmitted and distributed electricity to customers in its
service territory.
In late-1996, the Customer Choice Act was enacted to deregulate the
generation services market and provide a competitive market for generation of
electricity in Pennsylvania. The Customer Choice Act did not require public
utilities to legally separate their generation assets by transferring them to
separate corporate entities, but it did require the unbundling of electric
rates for separate generation, transmission and distribution services and
mandated open retail competition for generation services, commencing January 1,
1999. In order to better position itself in the new competitive marketplace
created by the Customer Choice Act, PPL Corporation realigned its family of
companies on July 1, 2000. As part of the realignment, PPL Electric Utilities'
generation and power marketing assets were transferred to newly formed
subsidiaries of PPL Corporation. PPL Electric Utilities' generation assets were
transferred to PPL Generation and its wholesale and retail power marketing
assets were transferred to PPL EnergyPlus. Also, as part of the realignment,
PPL Corporation's international development subsidiary, PPL Global, transferred
its domestic generation assets to PPL Generation. See Note 1 to the December
31, 2000 Financial Statements.
INDUSTRY DEREGULATION
The United States electric industry, which includes companies engaged in
providing electric 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 electric 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.
The Energy Policy Act of 1992 introduced more competition into the industry
by creating EWGs, a new class of generators that are not subject to significant
portions of the regulatory structure otherwise generally applicable to electric
utilities and their holding companies. It also empowered the FERC to require
that the owners and operators of electric transmission facilities make their
transmission facilities available on a nondiscriminatory basis to all wholesale
generators, sellers and buyers of electricity. In addition, state regulators
throughout the United States have begun to establish a framework to allow
retail customers to choose their electric suppliers, with incumbent utilities
required to deliver that electricity over their transmission and distribution
systems. Various states are in different stages of the process of determining a
framework for such deregulation. See "--Regulation" below.
As part of the transition to a deregulated market, a number of electric
utilities nationwide have divested or are in the process of divesting all or a
portion of their electric generation 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. Electric 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 the industry is
also likely to increase competition in the future and may result in lower
electric prices and less profit for all competitors in the United States
electric generation industry. See "-- Competition" below. Some restructured
markets, such as California, have recently experienced supply problems and
price volatility. These supply problems and price
48
volatility have been the subject of a significant amount of press coverage,
much of which has been critical of restructuring initiatives. In some of these
markets, government agencies and other interested parties have made proposals
to delay market restructuring or even re-regulate areas of these markets that
have previously been deregulated. See "-- Regulation" below.
In addition to deregulation in the United States, many foreign governments
have been privatizing their utilities and their transmission and distribution
networks and developing regulatory structures that are expected to encourage
competition in the sector. In addition, many countries have adopted active
government programs designed to encourage private investment in power
generation and energy delivery facilities. We believe that these market trends
have and will continue to create opportunities to expand our business in those
countries.
BUSINESS STRATEGY
Our objective is to be a leading, asset-based provider of wholesale and
retail energy and energy-related products and services in the northeastern and
western United States. We plan to achieve this objective by generating and
selling competitively priced energy in large, high-growth markets. In addition,
we also plan to continue to operate high-quality energy delivery businesses in
selected regions around the world. The key elements of our strategy are as
follows:
DEVELOP AND ACQUIRE ADDITIONAL GENERATION FACILITIES IN OUR TARGET MARKETS
Our objective is to continue to expand our ownership or control of current
domestic generation capacity in our target markets. When added to the 8,509 MW
of generation capacity we already own or control in Pennsylvania, our recently
completed acquisitions of Montana generation facilities, representing 1,157 MW,
and hydroelectric assets in Maine (including an interest in an oil-fired
generation facility), representing 96 MW, significantly enhance our ability to
reach this objective.
In addition, we are developing or constructing new power projects in
Arizona, Connecticut, Illinois, New York, Pennsylvania and Washington
representing an additional 4,605 MW of capacity, as more fully described under
"-- Properties and Projects." These facilities will consist of gas-fired
combined and simple cycle technology-based generation units that are expected
to commence operations at various times between 2001 and 2005. We also will
continue to actively evaluate opportunities to acquire operating generation
facilities or develop new generation projects in our target markets. We believe
that the northeastern and western regions of the United States are particularly
attractive markets because the existing and projected supply and demand
dynamics for power in these regions will require the construction of new
generation facilities to meet expected increased customer demand.
OPERATE A DIVERSE AND LOW-COST PORTFOLIO OF GENERATION ASSETS
We seek to operate an efficient and low-cost generation asset portfolio that
is diversified as to geography, fuel source and operating characteristics. Our
current generation facilities, as well as our new generation projects under
development or construction, are strategically located in our target markets
and provide us with a geographically diverse presence in the northeastern and
western United States, which helps to mitigate the risks resulting from
regional price differences. Our current portfolio of generation assets is also
well-diversified by fuel type with 46% of our total generation capacity coming
from coal, 22% from natural gas/oil, 20% from nuclear, 8% from hydro and from
4% other, as of September 30, 2001. Our coal-fired capacity is located in the
eastern and western United States and benefits from the low fuel costs
resulting from the relatively close proximity of our plants to coal fields and
low transportation costs, our extensive experience in acquiring low-cost coal
and our highly-efficient coal-fired plant technology. The generation assets are
also diversified with respect to dispatch, consisting of 74% baseload units,
20% intermediate load units and 6% peaking load units, as of September 30,
2001. Our current generation portfolio is weighted towards low-cost baseload
generation units, which helps reduce the
49
volatility of our revenues. Our new development projects involve new
intermediate and peaking facilities utilizing natural gas-fired, combined and
simple cycle technology-based generation units. These new units which will
allow us to further diversify our fuel mix, enhance our ability to capture the
potential benefits of peak period pricing and provide us with additional
operational flexibility and ancillary service revenues.
PURSUE ADDITIONAL REVENUES THROUGH ASSET-BASED TRADING OPPORTUNITIES
We intend to grow and diversify our revenue base by capitalizing on energy
marketing and trading opportunities in the increasingly deregulated United
States electricity market. We believe that our ability to market and trade
around our physical portfolio of generation assets through our integrated
generation, marketing and trading functions will provide us with attractive
opportunities to grow our revenues. In pursuing these opportunities, we attempt
to limit our financial exposure by following a comprehensive risk management
program. In particular, and consistent with our asset-based strategy, we
generally seek to execute contractual commitments for energy sales that do not
exceed our ability to produce the energy required. We employ sophisticated
trading practices to capture regional arbitrage opportunities and maximize the
value of our generation capacity. In addition, we seek to capture a diverse
stream of revenues and avoid over-reliance on any one market or type of
customer. As a result of our generation asset portfolio, our asset-backed
approach to marketing and trading and our comprehensive risk management
program, we believe we are well-positioned to grow our revenues while limiting
the potential impacts of energy price volatility.
CAPITALIZE ON SELECTED INTERNATIONAL TRANSMISSION AND DISTRIBUTION
OPPORTUNITIES
Our international strategy is focused on effectively managing our current
portfolio of energy transmission and distribution businesses in Latin America
(primarily Brazil, Chile and El Salvador) and the United Kingdom as more fully
described under "-- International Energy Projects."
We have concentrated our international development activities in markets
that we believe encourage investment in distribution assets and exhibit
potential for high growth in demand for electric distribution and related
services. We seek to maximize the financial and operational performance of each
of our investments by implementing best-practice management and operating
techniques to improve operating efficiencies, reduce operating costs and
improve customer service to achieve increased customer loyalty. We plan to
remain focused on customer-oriented businesses, which include the distribution
and supply of electric power, as well as telecommunications and other services,
to industrial, commercial and residential customers. We also seek to use our
regional presence to access and better evaluate potential investment
opportunities that may present potential synergies with existing projects or
future investments.
In Latin America, we continue to improve commercial processes from meter
reading through payment and collection, service quality and workforce
performance. For example, CEMAR personnel in Brazil are ahead of schedule in
installing new, more reliable meters throughout their system. The new meters
are expected to reduce electricity losses due to unmetered usage.
In the United Kingdom, we have focused on investing in electricity
distribution businesses that operate in a stable operating and regulatory
environment. We believe these distribution companies will produce strong and
predictable cash flows due to stable demand and regulated tariffs, and that we
have the opportunity to improve efficiencies relative to operating costs,
capital investments and reliability of service.
50
COMPETITIVE ADVANTAGES
We believe we are well positioned to successfully compete in the markets in
which we have chosen to focus. Our high-availability, low-cost baseload
generation in Pennsylvania, Montana and Maine provide our greatest advantage. A
majority of our capacity comes from low-cost baseload units that dispatch
before higher-cost marginal units and, as a result, can earn substantial
revenues. Our strategic access to the large energy markets in PJM, NEPOOL and
the WSCC is another key advantage.
Another key advantage is that our generation portfolio is diversified by:
. REGION--across the United States, and within regions, through our
participation in multiple markets (PJM, NEPOOL and WSCC). A key benefit
from this regional diversification is that there is a relatively low
correlation between power prices between the eastern and western regions
of the United States. Given this relatively low correlation across
regions, the geographic diversification of our generation units
mitigates our exposure to regional price volatility. For example, our
western PJM generation portfolio has good access to the very large
Midwest power markets, which have a history of price spikes. While there
are many influences on price spikes that will necessarily make any
forecasts unpredictable, we believe our generation assets are
well-positioned to take advantage of these price differentials,
especially those between the eastern and western United States.
. FUEL SOURCE--coal accounts for 46%, or 4,480 MW of our portfolio
capacity. Our coal-fired capacity is located in both the eastern and
western United States and is run in a baseload mode due to low fuel
costs resulting from the proximity of our plants to coal fields. Nuclear
accounts for 20%, or 1,995 MW of the capacity, and again, low fuel costs
cause these units to run in baseload mode. Hydro plants account for 8%,
or 803 MW of the capacity. Natural gas/oil units account for 22%, or
2,146 MW of capacity, and other accounts for 4%, or 338 MW of capacity.
[CHART]
Fuel Diversity - (as of September 30, 2001)
Coal 46%
Nuclear 20%
Gas/oil 22%
Hydro 8%
Other 4%
51
. OPERATING TYPE--our generating portfolio consists of a diversified mix
of operating units. Our hydroelectric, nuclear and coal units typically
serve as baseload units due to their low operating costs and design
characteristics. We have several units that can be used to meet
intermediate load requirements since they have somewhat higher operating
costs than our baseload units but can be held on standby for times when
customer demand increases. We also have a portfolio of gas-fired
turbines that, while incurring somewhat higher operating costs, can be
brought up to full power from an idle position within 10-15 minutes to
meet peak customer demand periods.
[CHART]
Operational Diversity - (as of September 30, 2001)
Baseload 74%
Peaking 6%
Intermediate/(1)/ 20%
/(1)/Our intermediate units include our Martins Creek Units 3 and 4, which
are dual fuel units that we view as high-intermediate units. Stone &
Webster Consultants classified these units as peaking units in their
Independent Technical Review, and reported a generating portfolio in
2000 consisting of 73% baseload, 5% intermediate and 22% peaking units.
Other of our key operating characteristics are:
. An eight-year contract with PPL Electric Utilities to provide all of its
PLR load requirements, which positions us to lock in attractive margins
on a substantial portion of our anticipated energy sales during the
2002-2009 period;
. Our extensive knowledge, experience and proven track record in power
plant and power systems operations, allowing us to use our assets in a
manner that maximizes value. Through various subsidiaries, our parent,
PPL Corporation, has owned and operated a diverse portfolio of
generating assets for over 75 years. The generating assets in our
portfolio have generally achieved and sustained operating performance in
terms of availability above average in comparison to similar units owned
and operated by our competitors;
. An integrated generation, marketing and fuel procurement strategy;
. A management team that is comprised of seasoned individuals who have
long-standing experience with our industry, market conditions, commodity
trading and risk management, business development and labor relations;
. An existing comprehensive risk management program designed to
proactively monitor and manage our exposure to market price risks; and
. A focused attention on international electric transmission and
distribution operations in two regions--the United Kingdom and Latin
America.
52
RISK MANAGEMENT
We follow a comprehensive risk management program that has been approved by
our board of managers and PPL Corporation's board of directors and its Risk
Management Committee ("RMC"). PPL Corporation's risk management oversight and
organizational structure is designed to identify, measure, evaluate and manage
price and credit risks resulting from exposures arising through activities tied
to buying and selling electric energy and gas, fuel procurement, the issuance
of debt and entering into and participating in international business
activities. PPL Corporation's RMC reports to PPL Corporation's board of
directors and finance committee and serves at the direction of such finance
committee. The RMC approves risk management programs and establishes risk
limits to manage the financial risk associated with energy trading, fuel
procurement, financing, global investments and international business
activities.
PPL EnergyPlus employs a risk manager and PPL Corporation employs a trading
controls staff that report to senior management of PPL Corporation and the RMC.
Together, their responsibilities include oversight of risk policy compliance,
consultation on proposed transactions, monitoring of aggregate price risk of
exposures and regular reporting, stress testing and scenario analysis. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Condition" and "-- Market Risk Sensitive Instruments"
for additional information.
We believe we are in compliance with approved risk limits of the RMC. Our
risk management programs and their principal objectives are as follows:
FUEL PROCUREMENT AND MARKETING & ENERGY TRADING
. Maintain financial risk associated with wholesale and retail market
participation within pre-determined limits; and
. Manage costs relating to fuel procurement.
DEBT FINANCING (INTEREST RATES)
. Achieve the lowest possible cost of debt financing while managing
volatility in interest rates by applying a mix of fixed and floating
rate debt either directly or through the use of derivative products
available in the financial markets; and
. Match debt service requirements to projected cash flow from assets.
GLOBAL INVESTMENTS & INTERNATIONAL BUSINESS ACTIVITIES (FOREIGN CURRENCY
EXCHANGE RATES)
. Protect cash flow exposures (transaction and anticipated commitments)
related to global investments and business activities and the U.S.
dollar value of foreign assets from adverse currency movements by
engaging in hedging activities to manage financial risk.
CREDIT RISK (COUNTERPARTIES)
. Maximize the return on investment in receivables while minimizing
possible days sales outstanding and bad debt write-offs by actively
managing counterparty credit exposures.
OUR SELECTED MARKETS
DOMESTIC MARKETS
North America is divided for administrative and energy transmission purposes
into ten geographic areas commonly referred to as "reliability councils."
Transmission constraints limit transfers between and within
53
reliability councils. As a result, each reliability council, or portion of a
reliability council, generally constitutes a separate market for power. The
reliability councils are responsible for overseeing the reliable operation of
the energy system. Our existing generation facilities are located in the
Mid-Atlantic, Western and New England regions of the United States and
primarily sell their output in portions of the Mid-Atlantic Area Council, the
WSCC, the Northeast Power Coordinating Council and the East Central Area
Reliability Council, or ECAR.
As part of the deregulation of the electric power industry, in some regions,
the role of managing principally the transmission of energy is being assumed by
ISOs and regional transmission organizations, or RTOs, which will supervise a
market-based system for transmission and, in some instances, generation of
electric power. The FERC oversees the operations of these organizations and
requires ISOs and RTOs to be independent from market participants.
In a July 2001 order, the FERC concluded that it is necessary that the New
York Power Pool, or NYPP, PJM and NEPOOL, combine to form one Northeast RTO. We
strongly support the most comprehensive amalgamation of the existing and
proposed northeast pools, including the establishment of a single Northeast RTO
as well as the elimination of marketplace distinctions and control area
boundaries. We believe that the FERC's proposal represents a significant step
forward in establishing a reliable and properly functioning wholesale
electricity market in the region. In a concurrent July 2001 order, the FERC
directed the NYPP, PJM, NEPOOL and Allegheny Power to participate in mediation
discussions on forming a single Northeast RTO. The mediation discussions
commenced on July 24, 2001, and ran through September 7, 2001. PPL EnergyPlus,
our marketing and trading subsidiary, was one of the parties participating in
these discussions. The participants submitted a business plan for the
development and implementation of a single RTO for the Northeastern United
States to the mediator on September 10, 2001, and the mediator submitted the
plan and accompanying report to the FERC on September 17, 2001. We cannot
predict whether the proposal to establish a single Northeast RTO will be
implemented.
NORTHEAST (PJM AND NEPOOL)
Approximately 75% of our existing and under development or construction
generation capacity is located in eastern markets, with 70% concentrated in
Pennsylvania. Our Pennsylvania generation plants, including nuclear, coal,
gas/oil, and combustion turbine units, are focused on the
Northeast/Mid-Atlantic energy markets including NEPOOL and PJM. We also serve
the markets in the Northeast with our oil and hydro generation units located in
Maine; however, this represents less than 1% of our total current capacity.
The PJM power exchange is the largest centrally-dispatched power pool in the
U.S., with over 56,000 MW of pooled generation capacity. It encompasses New
Jersey, Delaware, and the District of Columbia, the majority of Maryland and
Pennsylvania, and the Delmarva Peninsula area of Virginia. PJM has facilitated
a bid-based energy market since 1997, and on January 1, 1998 became the first
operational ISO in the United States. The PJM power exchange enables
participants to buy and sell energy and ancillary services, schedule bilateral
transactions and reserve transmission service, and is the most liquid and
active energy market in the U.S.
The PJM market is advantageous relative to other markets because the
generation plants located in PJM have direct transmission access to the NYPP,
ECAR and the Virginia Carolina Reliability Group, or VACAR, areas. Most of our
PJM generation facilities are located in western PJM. These operating plants
have access to the higher priced eastern and southern PJM markets, as well as
access to the very large Midwest power markets, including the ECAR market.
NEPOOL was formed as a voluntary association of utilities in New England
that established a single regional network to direct the operations of the
major bulk power generation and transmission facilities in the region. On July
1, 1997, NEPOOL established ISO New England Inc., a not-for-profit corporation
charged with the day-to-day direction, operation and management of the bulk
power system and administering the region's open access transmission tariff.
54
The capacity mix in NEPOOL is diverse, with significant portions of the
total installed capacity coming from coal, nuclear, hydro, combined cycles,
turbines, oil and gas steam units, pumped storage units and non-utility
generation units. Although conventional utility oil and gas steam capacity is
the largest component of the capacity mix in NEPOOL, the baseload capacity is
dominated by hydro and nuclear capacity.
WESTERN REGION (WSCC)
Approximately 22% of our existing and under development or construction
generation capacity is located in the WSCC. The WSCC is the single largest
North American Energy Reliability Council region in geographic terms,
encompassing approximately 1.8 million square miles and including all or part
of 14 western states and British Columbia, Canada. According to the independent
market consultant, the area contains over 150,000 MW of installed generation
capacity. Our generation capacity located in Montana, consisting of coal and
hydro plants, is focused on the western markets within the WSCC, with the
Northwest being our primary regional market. Montana is our single most
important regional market, receiving approximately 80% of the Montana
generation facilities' output. The remainder of this output is exported to a
number of markets in the Northwest and elsewhere in the WSCC. Unlike PJM or
NEPOOL, there is no independent power pool in the WSCC. In general, energy
supply markets in the WSCC, and particularly in Montana, are based on direct
bilateral contracts between energy generators and energy purchasers.
Montana enacted deregulation legislation that would have made direct access
available for all energy customers by June 30, 2002, but subsequent legislation
has extended the transition period for customers to select an alternative
energy supplier to July 1, 2007. The extension also has the effect of
continuing Montana Power (or its successor) as the default supplier during the
extended transition period. See "-- PPL Energy Supply's Domestic Properties and
Projects -- Montana" for a description of certain transition agreements between
PPL Montana and Montana Power, and "Legal Proceedings" for a description of a
related lawsuit.
Large industrial customers may select an alternative supplier under the
Montana deregulation legislation. 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. Due to our
competitive cost of supply and the transmission costs to import energy into
Montana, we expect to offer many of these customers competitive supply.
CALIFORNIA
We have sold electricity into the California markets. Since deregulating in
1997, California has implemented an ISO and commenced operation of the
California Power Exchange. Until recently, the California Power Exchange had
active day-ahead and real-time energy trading markets. The California Power
Exchange recently ceased operating a spot market in California, due to several
factors, including:
. a shortage of generation capacity in California;
. the statutory obligation of utilities to purchase all of their
customers' requirements in the short-term spot markets operated by the
California Power Exchange;
. the substantial and rapid increase in power prices in the spot market
due to the shortage of capacity;
. the substantial and rapid increase in the cost of natural gas for power
generation;
. a retail rate-freeze that prohibited California utilities from passing
these increased costs through to their customers in California; and
. transmission constraints that impaired the movement of power in bulk
power markets.
55
Earlier in 2001, the State of California negotiated long-term bilateral
contracts with parties who had agreed to construct new capacity in California.
After the bilateral contracts were executed, spot market prices for power in
California declined due, in part, to:
. cooler than normal summer weather conditions;
. decline in demand for electricity due to a slow down in the economy;
. implementation of price mitigation measures by regulators; and
. increase in generating capacity in California due to recent construction
by developers acting in reliance on the bilateral contracts.
The Public Utilities Commission of the State of California, or CPUC, has
recently taken the position that the prices negotiated under these bilateral
contracts are above the current market price and the CPUC has made multiple
filings at the FERC seeking a determination that the State of California would
no longer be obligated to pay the prices negotiated under these long-term
bilateral contracts. We are not currently making sales into the California
markets and we are not a party to any of the bilateral contracts with the State
of California. At this time we cannot predict what the California marketplace
will look like in the immediate or long-term future. See "Risk Factors,"
"Business--Legal Proceedings," Note 17 to the December 31, 2000 Financial
Statements and Note 11 to the September 30, 2001 Financial Statements.
TRANSMISSION INTERCONNECTIONS
Our generation facilities are well positioned for access to transmission
interconnections. Our generation in the East is located primarily within PJM,
with a concentration in the western part of PJM. We also own generation
capacity within the NEPOOL. Our generation capacity in the West is
strategically located in the WSCC. We believe that being regionally
diversified, with generation facilities located in both areas, provides us with
a hedge against regional price differentials.
In the East, our facilities in PJM have transmission access to the ECAR,
which is to the west, the VACAR, which is to the south, and the NYPP, which is
to the north and east. In addition, although PJM has an extensive internal
transmission network, it nonetheless experiences some transmission constraints.
While the eastern part of PJM is congested, PJM provides hedging mechanisms for
system users. We purchase financial instruments across transmission systems to
extract value from the day ahead markets, due to inefficiencies in the
marketplace. These instruments are purchased in periodic auctions held by the
ISOs and are settled based on differences in locational marginal price between
defined points, due to transmission limitations.
In the West, we are positioned within the WSCC which is a highly
interconnected area that includes most of the contiguous United States west of
the Mississippi River, British Columbia and Alberta, Canada. We have provided
energy into the capacity-short West.
Due to the location of our existing generation facilities and our
exploration of a wide range of potential siting opportunities for our new
capacity additions, we believe that we will be able to access our target
markets effectively despite potential transmission constraints.
56
DOMESTIC PROPERTIES AND PROJECTS
We operate, through subsidiaries, power plants in Pennsylvania, Montana and
Maine and develop and operate international energy projects in Latin America
and Europe. We are also developing energy projects in Arizona, Connecticut,
Illinois, New York, Pennsylvania and Washington State. The Summary Independent
Technical Review includes a detailed description of our properties and
projects. The following tables summarize some of the key aspects of our
properties and projects.
DOMESTIC GENERATION
(WINTER RATING)
TOTAL NET
MEGAWATT PPL OWNERSHIP
CAPACITY OF INTEREST
PLANT TYPE PLANT/(1)/ IN NET MW/(1)/ IN SERVICE DATE
- -------------------------------------- ----------------------- ----------- --------------- ---------------
PENNSYLVANIA
Montour............................... Coal-fired steam 1,536 1,536 (100%) 1973
Brunner Island........................ Coal-fired steam 1,473 1,473 (100%) 1961-1969
Martins Creek (Units 1 & 2)........... Coal-fired steam 300 300 (100%) 1954-1956
Keystone.............................. Coal-fired steam 1,702 210 (12.34%) 1967-1968
Conemaugh............................. Coal-fired steam 1,711 278 (16.25%) 1970
------ ------
TOTAL COAL-FIRED..................... 6,722 3,797
------ ------
Susquehanna........................... Nuclear-fueled steam 2,217 1,995 (90%) 1983-1985
Martins Creek (Units 3 & 4)........... Gas and oil-fired steam 1,640 1,640 (100%) 1975-1977
Combustion turbines and diesels....... Gas-fired steam 454 454 (100%) 1967-1971
Hydroelectric......................... Hydroelectric 146 146 (100%) 1910-1986
------ ------
TOTAL SYSTEM CAPACITY--PENNSYLVANIA.. 11,179 8,032/(2)/
------ ------
MONTANA
Colstrip Units 1 & 2.................. Coal-fired thermal 614 307 (50%)/(3)/ 1975-1976
Colstrip Unit 3....................... Coal-fired thermal 740 222 (30%)/(4)/ 1984
Corette............................... Coal-fired steam 154 154 (100%) 1968
------ ------
TOTAL COAL-FIRED..................... 1,508 683
------ ------
Hydroelectric......................... Hydroelectric 474 474 (100%) 1906-1958
------ ------
TOTAL SYSTEM CAPACITY--MONTANA....... 1,982 1,157 (100%)
------ ------
MAINE
Wyman Unit 4.......................... Oil-fired generation 624 52 (8.33%) 1978
Hydroelectric......................... Hydroelectric 51 44 (86%)/(5)/ 1916-1988
------ ------
TOTAL SYSTEM CAPACITY--MAINE......... 675 96
------
TOTAL SYSTEM CAPACITY--PPL GENERATION... 9,285/(2)/
------
- --------
/(1)/At September 30, 2001. The capacity of generation units is based upon a
number of factors, including the operating experience and physical condition
of the units, and may be revised from time to time to reflect changed
circumstances. The net effect of Maine sales committed to Bangor Hydro is to
reduce Maine's system capacity by 65 MW to 31 MW.
/(2)/We also have 477 MW of firm purchases (including purchases associated with
our interest in Safe Harbor) that are not included in this figure. This
figure also excludes a 30MW upgrade to Martins Creek (Units 3 & 4) in
December 2000.
/(3)/PPL Montana leases a 50% undivided interest in Colstrip Units 1 and 2.
/(4)/PPL Montana leases a 30% undivided interest in Colstrip Unit 3. However,
because Colstrip Units 3 and 4 are identical units, PPL has contracted to
obtain 15% of the capacity from each of Colstrip Units 3 & 4.
/(5)/Includes our 50% interest in the West Enfield Station.
57
[CHART]
System Capacity
PENNSYLVANIA
The Pennsylvania plants, with a total capacity of 8,032 MW, were transferred
by PPL Electric Utilities to PPL Generation in the corporate realignment. PPL
Generation's subsidiaries operate the wholly-owned Pennsylvania power plants as
well as the Susquehanna nuclear plant. The electricity from our wholly-owned
Pennsylvania power plants and from our share of the output from Susquehanna,
Conemaugh and Keystone is sold to PPL EnergyPlus under power purchase
agreements filed with the FERC. We also have contracts for firm purchases of
477 MW of capacity. These contracts expire at various times through 2014.
During 2000, PPL Generation produced about 40.6 billion kWh in its
Pennsylvania plants, with 56% of the energy generated by coal-fired stations,
39% from nuclear operations at the Susquehanna station, 3% from the Martins
Creek gas and oil-fired station and 2% from hydroelectric stations.
SUSQUEHANNA. The Susquehanna plant is a 2,217 MW two-unit electric
generation facility located in Luzerne County, Pennsylvania. The units are
boiling water reactor nuclear power units that operate under 40-year operating
licenses from the NRC and provide baseload service. We plan to install
replacement turbines in 2003 and 2004 at an estimated cost of $120 million,
which would result in an additional capacity of 40 MW per unit. We also intend
to undertake steam flow meter modifications which will result in a standard
uprate of 11 MW at each unit. PPL Susquehanna, LLC, an indirect subsidiary of
PPL Energy Supply, owns a 90% undivided interest in each of the Susquehanna
units and Allegheny Electric Cooperative, Inc. owns the remaining 10% undivided
interest in the units. PPL Susquehanna is the facility's operator under the
owners' agreement and is the NRC licensee. The license for Unit 1 is scheduled
to expire in 2022 and the license for Unit 2 is scheduled to expire in 2024.
MONTOUR. The Montour plant is located in Montour County, Pennsylvania and
consists of two coal-fired steam-electric generation units.
BRUNNER ISLAND. The Brunner Island plant, located in York County,
Pennsylvania, consists of three coal-fired steam-electric generation units.
MARTINS CREEK. The Martins Creek plant is located in Lower Mount Bethel
Township, Pennsylvania, and consists of four steam-electric generation units,
consisting of two coal-fired units and two gas/oil-fired units.
58
KEYSTONE. The Keystone plant is located in Armstrong County, Pennsylvania and
consists of two coal-fired steam-electric generation units. We own a 12.34%
undivided interest in Keystone. There are six other co-owners of undivided
interests in the Keystone plant. Reliant Energy Northeast Management Company is
the operator.
CONEMAUGH. The Conemaugh plant is located in Indiana, Pennsylvania and
consists of two coal-fired steam-electric generation units and four diesel
generators. At December 31, 2000, we owned a 11.39% undivided interest in
Conemaugh. Our ownership increased to 16.25% in January 2001, as a result of
the purchase of an additional 4.8% interest, and now totals 278 MW. There are
six other co-owners of undivided interests in the Conemaugh plant and Reliant
Energy Northeast Management Company is the operator.
HYDROELECTRIC PLANTS
HOLTWOOD. The Holtwood plant is a 10-unit plant located on the Susquehanna
River in Lancaster County, Pennsylvania and includes a 0.5 mile long dam and
powerhouse. The combined capacity of the plant is 102 MW. The facility's FERC
license expires in 2014.
WALLENPAUPACK. The Wallenpaupack hydroelectric plant is located in
northeastern Pennsylvania on Lake Wallenpaupack and includes a dam with a
reservoir and a powerhouse that contains two units with a total capacity of 44
MW. The facility's license expires in 2004. We are working to have the facility
relicensed.
SAFE HARBOR. PPL Holtwood, LLC, one of our indirect subsidiaries, owns
one-third of the capital stock (one-half of the voting stock) of Safe Harbor
Water Power Corporation, also referred to as SHWPC, which owns the Safe Harbor
plant. The remaining two-thirds of the capital stock of SHWPC is owned by
Baltimore Gas & Electric Company. The total generation capacity of the Safe
Harbor plant is 418 MW, and PPL Holtwood is entitled by contract to one-third
of the plant's output (139 MW).
COMBUSTION TURBINES AND DIESELS. PPL Energy Supply, through its
subsidiaries, operates 23 peaking combustion turbines, all of which were
commissioned from 1967 to 1971. The combustion turbines burn distillate oils
but can also be converted to burn natural gas. The fleet is located at sites
throughout central-eastern Pennsylvania.
MONTANA
The Montana generation assets were acquired by PPL Global in December 1999
and were transferred to PPL Generation in the July 2000 corporate realignment.
The generation facilities are fueled by coal and hydro power, and have a net
capacity of 1,157 MW. The hydroelectric assets include eleven generation plants
and one storage reservoir without generation.
During 2000, PPL Montana generated 8.2 billion kWh. Of this total, 4.9
billion kWh was from fossil generation, with the balance from PPL Montana's
hydroelectric plants.
PPL Montana has two transition agreements to supply wholesale electricity to
Montana Power. One agreement provides for the sale of 200 MW from PPL Montana's
interest in Colstrip Unit 3 until December 2001. The other agreement covers
Montana Power's remaining native load commitments and lasts until the remaining
load is zero, but in no event later than June 2002. Excess generation is
available for wholesale marketing. We recently agreed to continue to supply
power to Montana Power after June 2002. See "Summary--Recent Developments."
In addition, as part of the purchase of generation assets from Montana
Power, PPL Montana agreed to supply electricity to the United States government
on behalf of the Flathead Irrigation Project. Under the agreement, which
expires in December 2010, PPL Montana is required to supply approximately 7.5
MW of capacity year round, with an additional 3.7 MW during the months of April
through October.
59
In connection with the acquisition of the Montana generation assets, PPL
Montana also is required to purchase a portion of Montana Power's interest in
the 500kV Colstrip Transmission System for $97 million. PPL Montana is
currently in discussions with Montana Power to pursue alternatives to acquiring
the entire interest in the transmission assets, so we cannot predict whether
PPL Montana will buy all, or less than all, of Montana Power's interest in the
Colstrip Transmission System or what the purchase price will be if a purchase
occurs.
COLSTRIP. The Colstrip facility is a four-unit, coal-fired, conventional
steam-cycle electric generation plant in Colstrip, Montana. PPL Montana has a
50% leasehold interest in Colstrip Units 1 and 2 and a 30% leasehold interest
in Colstrip Unit 3. Unit 4 is owned by a group of five other utilities. PPL
Montana operates the Colstrip facility. Units 3 and 4 are identical and are
operated together, and pursuant to the related operating agreement, PPL is
entitled to 15% of the capacity and energy from each of Units 3 and 4.
CORETTE. The Corette facility is located near Billings, Montana along the
Yellowstone River. The unit utilizes natural gas as a startup fuel and the
boiler burns low-sulfur coal to reduce emissions.
HYDROELECTRIC PLANTS
The following table includes information about PPL Montana's hydroelectric
plants. All are run-of-the-river facilities, which means that they use the
power in river water as it passes through the plant without causing an
appreciable change in the river flow or causing adverse water quality changes.
NET CAPACITY COMMERCIAL FERC LICENSE
FACILITY (MW)/ (1)/ OPERATION DATE EXPIRATION DATE LOCATION
-------- ------------ -------------- --------------- -----------------------------
Kerr.......... 189 1939 2035 Columbia River Basin
Thompson Falls 86 1915 2025 Columbia River Basin
Mystic........ 11 1927 2009/(2)/ West Rosebud Creek
Madison....... 9 1906 2040 Missouri--Madison River Basin
Hauser........ 17 1911 2040 Missouri--Madison River Basin
Holter........ 50 1918 2040 Missouri--Madison River Basin
Black Eagle... 18 1927 2040 Missouri--Madison River Basin
Rainbow....... 35 1910 2040 Missouri--Madison River Basin
Cochrane...... 54 1958 2040 Missouri--Madison River Basin
Ryan.......... 60 1915 2040 Missouri--Madison River Basin
Morony........ 48 1929 2040 Missouri--Madison River Basin
---
577
===
- --------
/(1)/Summer ratings at September 30, 2001. In the winter, these facilities
historically generate approximately 474 MW of energy due to lower average
water flow conditions. The capacity of generation units is based upon a
number of factors, including the operating experience and physical condition
of the units, and may be revised from time to time to reflect changed
circumstances.
/(2)/The Mystic facility's FERC license expires in 2009 and we are working to
have the facility relicensed.
MAINE
The Maine assets were acquired from Bangor Hydro in 1998. A portion of the
output of the Maine generation assets is sold to meet the retail load
requirement of Bangor Hydro. The Wyman Unit 4 output is being sold to
Constellation Energy through 2004. The West Enfield hydroelectric facility's
output will be sold to Bangor Hydro through the year 2024. The output from
other hydroelectric stations in Maine was sold to Bangor Hydro through March
2000. We are now selling this output on the open market.
During 2000, PPL Maine generated about 467 million kWh. Of this total, about
263 million kWh was from hydroelectric generation, with the balance from PPL
Maine's interest in the oil-fired Wyman Unit 4.
WYMAN. The Wyman plant is located in Yarmouth, Maine. PPL Energy Supply's
ownership interest in Wyman Unit 4 is 8.33% or 52 MW. The majority of Wyman
Unit 4 (59.15%) is owned by FPL Energy, Inc., which is also the operator of the
Wyman plant.
60
HYDROELECTRIC. All of our hydroelectric facilities in Maine are located on
the Penobscot River Basin except one that is located on the Union River. There
are currently seven operating hydroelectric projects containing a total of 48
generation units, and all but the one project on the Union River operate with a
run-of-river operating regime.
Under its purchase agreement with Bangor Hydro, PPL Maine entered into a
memorandum of understanding pursuant to which it has the right to develop a 345
KV line from the Canadian border to central Maine. We are participating in the
development of the transmission line, but do not intend to take an ownership
interest in it.
DOMESTIC DEVELOPMENT PROJECTS
The following table summarizes our domestic development projects.
DOMESTIC PROJECTS UNDER DEVELOPMENT/CONSTRUCTION
TOTAL MEGAWATT OUR OWNERSHIP EXPECTED
PLANT TYPE CAPACITY/(1)/ INTEREST IN MW IN SERVICE DATE/(2)/
----- --------------- -------------- ---------------- ---------------------
PENNSYLVANIA
Lower Mt. Bethel.......... Gas-fired 600 600 (100%) 2003
PA Peaking (5 facilities). Gas-fired 900 900 (100%) 2002-03
Susquehanna/(3)/.......... Nuclear 100 90 (90%) 2003-04
ARIZONA
Griffith.................. Gas-fired steam 600 300 (50%)/(4)/ 2001 (fourth quarter)
Sundance.................. Gas-fired 450 450 (100%) 2002
ILLINOIS
University Park........... Gas-fired 540 540 (100%) 2002
CONNECTICUT
Wallingford............... Gas-fired 225 225 (100%) 2001 (fourth quarter)
NEW YORK
Kings Park................ Gas-fired 300 300 (100%) 2003/(5)/
WASHINGTON
Starbuck.................. Gas-fired steam 1,200 1,200 (100%) 2004-05/(6)/
----- -----
TOTAL........................ 4,915 4,605
===== =====
- --------
/(1)/The capacity of generation units is based on a number of factors,
including the operating experience and physical condition of the units, and
may be revised from time to time to reflect changed circumstances.
/(2)/The expected in-service dates are subject to receipt of required approvals
and permits and to other contingencies.
/(3)/The Susquehanna project involves the installation of more efficient steam
turbines to increase capacity.
/(4)/The Griffith Energy project is being co-developed with Duke Energy, which
is also a 50% owner.
/(5)/Construction is expected to commence in 2002.
/(6)/Construction is expected to commence in 2003.
All projects under development are gas-fired simple-cycle or combined-cycle
combustion turbine facilities.
INTERNATIONAL OPERATIONS
PPL Global's major international operations include equity investments in
two United Kingdom electricity transmission and distribution companies: WPD
(South West), which serves customers in England, and WPD (South Wales), which
serves customers in Wales. PPL Global jointly owns these investments with
Mirant. PPL Global also has consolidated investments in electricity
transmission and distribution companies primarily serving customers in Chile,
El Salvador, Bolivia and Brazil.
61
INTERNATIONAL PROJECTS
TOTAL
OUR CUSTOMERS AT
PRIMARY OWNERSHIP DECEMBER 31, ELECTRICITY SALES
COMPANY LOCATION BUSINESS INTEREST 2000 GWH 2000
------- --------------- ------------ --------- ------------ -----------------
LATIN AMERICA
Empresas EMEL S.A. (EMEL): 95.4%
Emelari..................................... Chile Distribution 80.0% 53,000 }
Eliqsa...................................... Chile Distribution 83.4% 60,000 }
Elecda...................................... Chile Distribution 80.4% 116,000 } 1,830
Emelat...................................... Chile Distribution 93.4% 69,000 }
Emelectric.................................. Chile Distribution 99.9% 175,000 }
Emetal (owned by Emelectric)............... Chile Distribution 75% 14,000 }
Transemel................................... Chile Transmission 60% -- }
---------
487,000
Empresa de Luz y Fuerza Electrica Cochabamba
(ELFEC)...................................... Bolivia Distribution 91.9% 209,000 600
Distribuidora de Electricidad del Sur (DelSur) El Salvador Distribution 80.5% 216,000 900
Companhia Energetica do Maranhao (CEMAR)...... Brazil Distribution 89.6% 1,100,000 2,380
--------- ------
Subtotal................................... 2,012,000 5,710
Compania General de Electricidad (CGE)........ Chile/Argentina Distribution 8.6% 1,400,000 13,997
Latin American Energy and Electricity Fund
(FondElec):
Transredes S.A.............................. Bolivia Pipeline 0.5%/(1)/ N/A N/A
Cataguazes Leopoldina......................... Brazil Distribution 1.2%/(1)/ 685,000 2,043
--------- ------
Subtotal................................... 2,085,000 16,040
Empresa Electica Valle Hermosa S.A. (EVH)..... Bolivia Generation 14.7% /(2)/
Aguaytia Energy, LLC.......................... Peru Generation 11.4% /(3)/
--------- ------
Subtotal Latin America..................... 4,097,000 21,750
EUROPE
WPD (South West).............................. U.K. Distribution 51.0% 1,400,000 14,900
WPD (South Wales)............................. U.K. Distribution 51.0% 1,000,000 12,400
Teesside Power Limited........................ U.K. Generation 15.4% /(4)/
Hidrocentrais Reunidas, LDA................... Portugal Generation 50.0% /(5)/
Hidro Iberica, B.V............................ Spain Generation 50.0% /(5)/
--------- ------
Subtotal Europe............................ 2,400,000 27,300
--------- ------
Total................................... 6,497,000 49,050
- --------
/(1)/Represent our aggregate ownership interest.
/(2)/The total net generation capacity of EVH is 194 MW.
/(3)/The total net generation capacity of Aguaytia is 155 MW.
/(4)/The total net generation capacity of Teesside is 1,875 MW.
/(5)/The combined total net generation capacity of Hidrocentrais Reunidus and
Hidro Iberica is 66 MW.
WESTERN POWER DISTRIBUTION (WPD (SOUTH WEST) AND WPD (SOUTH WALES))
PPL Global owns 51% of WPDH, which owns WPD (South West), a British regional
utility which distributes electricity to approximately 1,400,000 customers in
southwest England. The balance of WPD (South West) is owned by Mirant. On
August 23, 2000, PPL Global and Mirant, through WPDL, made an offer to acquire
all of the outstanding shares of Hyder, an integrated utility in Wales, for
approximately $847 million and the assumption of approximately $3.2 billion of
debt. Control was acquired in September 2000 and the acquisition completed in
December 2000.
At that time, Hyder owned and operated the electricity network in South
Wales and the water distribution and waste water treatment business for all of
Wales. Subsequently, the non-electric distribution elements of Hyder were sold
and the electric distribution company, renamed WPD (South Wales), was
integrated into
62
WPDH. WPD (South Wales) is a regional electric distribution company serving
approximately 1 million customers in Wales. Its 4,550-square-mile service
territory is adjacent to WPD (South West)'s territory in southwest England. We
own a 51% economic interest in WPD (South Wales) through our joint ownership of
WPDH. We and Mirant share control of WPD (South West) and WPD (South Wales)
equally.
WPDH owns a 15.4% stake in Teesside Power Limited, which owns and operates a
1,875 MW combined cycle generating plant in Northeast England.
The electric distribution companies include the following:
EMPRESAS EMEL S.A. (EMEL)
PPL Global owns 95.4% of Emel, which is a holding company for six Chilean
electric distribution companies (Emelectric, Elecda, Eliqsa, Emelari, Emelat
and Emetal) that serve 487,000 customers in northern and central Chile. Each of
the distribution companies is operating under an exclusive concession granted
by the Ministry of Economy, Development and Reconstruction.
COMPANHIA ENERGETICA DO MARANHAO (CEMAR)
PPL Global owns 89.6% of CEMAR, which distributes and sells electricity in
the Brazilian state of Maranhao under a thirty year concession agreement
between the Government of Brazil and CEMAR. Maranhao occupies an area of
333,366 square kilometers and has an estimated population of 5.4 million people.
DISTRIBUIDORA DE ELECTRIDAD DEL SUR (DELSUR)
PPL Global owns 80.5% of DelSur. DelSur is a registered electricity
distributor which carries out the distribution and sale of electricity in an
area consisting of mainly the Departments of Libertad, Cuscatlan and San
Salvador. The authorized area encompasses approximately 4,138 square kilometers
in central and southern El Salvador, including part of San Salvador city, and
urban and rural loads in the outlying region. DelSur serves approximately
216,000 customers, of which a majority are residential loads.
EMPRESA DE LUZ Y FUERZA ELECTRICA COCHABAMBA S.A. (ELFEC)
PPL Global owns 91.9% of Elfec, which serves 209,000 customers in the
Cochabamba area in Bolivia under a forty year exclusive concession agreement
with the Bolivian government.
OTHER INTERNATIONAL INVESTMENTS AND PROJECTS
In addition to international electric distribution companies, PPL Global
also owns several international generation assets. These assets are Empresa
Electrica Valle Hermosa S.A., or EVH, in Bolivia, Aguaytia in Peru, and several
hydroelectric plants in Spain and Portugal. EVH is an electric generation
company that operates two natural gas-fired power plants and three
hydroelectric units. The total generation capacity of EVH is 194 MW. PPL Global
owns 14.7% of EVH. Aguaytia consists of a natural gas field and two
simple-cycle combustion turbines. The total output of the project is 155 MW
which is carried by a dedicated 250-mile 220 kV transmission line from central
Peru over the Andes Mountains to the coast north of Lima. PPL Global owns 11.4%
of Aguaytia. The hydroelectric plants in Spain and Portugal have a combined
installed capacity of 66 MW. PPL Global has a 50% ownership stake in these
generation assets.
We own an 8.6% equity interest in Compania General de Electricidad, or CGE,
a leading energy distribution company in Chile and Argentina and the largest
distributor of electric power in Chile. CGE provides electricity delivery
services to 1.4 million customers in Chile and natural gas delivery services to
200,000 customers in Santiago. The company also distributes liquid gas and
natural gas in Chile and Argentina, distributes electricity in Argentina,
participates in the telecommunications business in Chile, and produces meters,
transformers, and cement.
63
PPL Global also owns a 17% interest in the Latin America Energy and
Electricity Fund (FondElec) which has energy holdings in Bolivia and Brazil.
Through our FondElec holdings, we have the following:
. a 0.5% ownership stake in Transredes S.A., a natural gas and oil
pipeline operator in Bolivia; and
. a 1.2% ownership stake in Cataguazes Leopoldina, an electric
distribution company serving eastern Brazil.
FUEL MANAGEMENT AND PROCUREMENT
Fuel management and procurement includes coal mine management and coal
procurement, and fuel transportation including fleet train management, nuclear
supply and conversion agreements and gas and oil pipeline operations.
COAL
We procure coal for our baseload and intermediate-load coal units utilizing
a blend of long-term and short-term contracts and spot market purchases with
the objective of optimizing coal cost and mitigating supply risks.
For our Pennsylvania generation facilities, we actively manage our supply
base in three principal areas including central Appalachia, western
Pennsylvania and central Pennsylvania. Our proximity to these coal fields
affords us access to relatively low-cost coal. In addition, we benefit from our
management and operation of a fourteen unit train operation which includes a
fleet of approximately 1,400 rail cars.
During 2000, about 57% of the coal delivered to our Pennsylvania generation
stations was purchased under long-term contracts and 43% was obtained through
open market purchases. These contracts provided our generation facilities with
about 4.2 million tons of coal in 2000 and are expected to provide 4.9 million
tons in 2001. We plan to meet additional coal requirements for our plants in
Pennsylvania through contracts and open market purchases.
The amount of coal in inventory at Pennsylvania generation stations varies
from time to time depending on market conditions and plant operations. At
December 31, 2000, these plants held a supply sufficient to cover about 20 days
of operations.
The coal burned at our Pennsylvania generation stations contains both
organic and pyritic sulfur. Mechanical cleaning processes are utilized to
reduce the pyritic sulfur content of the coal. The reduction of the pyritic
sulfur content by either mechanical cleaning or blending has lowered the total
sulfur content of the coal burned to levels which permit compliance with
current sulfur dioxide emission regulations established by the Pennsylvania
Department of Environmental Protection, or DEP.
Our coal-fired generation capacity in Montana includes our interests in the
Colstrip and Corette facilities. Our coal needs with respect to our interests
in Colstrip Units 1 and 2 are covered by a long-term coal contract effective
through December 31, 2009, and, with respect to our interest in Colstrip Unit
3, by a long term contract effective through December 31, 2019. PPL Montana has
a one-year contract relating to the Corrette plant to purchase low sulfur coal,
expiring in December 2001, which has been extended through 2003.
PPL Generation owns a 12.34% undivided interest in the Keystone station and
a 16.25% undivided interest in the Conemaugh station. The owners of the
Keystone station have a long-term contract with a coal supplier that provides
2.8 million tons per year until the contract expires at the end of 2004. The
balance of the Keystone station requirements are purchased in the open market.
The coal supply requirements for the Conemaugh station are being met from
several sources through a blend of long-term and short-term contracts and spot
market purchases.
64
NUCLEAR
Our nuclear generation facility, PPL Susquehanna, has executed uranium
supply and conversion agreements that satisfy 75% of its uranium requirements
in 2001, approximately 35% of its requirements in 2002-2003 and, including
options, an additional 25% of its requirements for the period 2004-2007.
Deliveries under these agreements are expected to provide sufficient uranium to
permit Units 1 and 2 to operate into the first quarter of 2002.
PPL Susquehanna has executed an agreement that satisfies all of its
enrichment requirements through 2004. Assuming that the other uranium
components of the nuclear fuel cycle are satisfied, deliveries under this
agreement are expected to provide sufficient enrichment to permit Unit 1 to
operate into the first quarter of 2006 and Unit 2 to operate into the first
quarter of 2007.
PPL Susquehanna has entered into an agreement that, including options,
satisfies all of its fabrication requirements through 2006. Assuming that the
uranium and other components of the nuclear fuel cycle are satisfied,
deliveries under this agreement are expected to provide sufficient fabrication
to permit Unit 1 to operate into the first quarter of 2008 and Unit 2 to
operate into the first quarter of 2007.
Federal law requires the federal government to provide for the permanent
disposal of commercial spent nuclear fuel. Under the Nuclear Waste Policy Act,
the Department of Energy, or DOE, initiated an analysis of a site in Nevada for
a permanent nuclear waste repository. Progress on a proposed disposal facility
has been slow, and the repository is not expected to be operational before
2010. As a result, it was necessary to expand Susquehanna's on-site spent fuel
storage capacity. PPL Susquehanna contracted for the design and construction of
a spent fuel storage facility employing dry cask fuel storage technology. The
facility is modular, so that additional storage capacity can be added as
needed. The new facility began receiving spent nuclear fuel in October 1999.
PPL Susquehanna estimates that there is sufficient storage capacity in the
spent nuclear fuel pools and the on-site dry spent fuel storage facility at
Susquehanna to accommodate discharged fuel through the life of the plant, if
necessary.
Federal law also provides that generators of spent fuel are responsible for
certain costs of disposal. In January 1997, PPL Electric Utilities joined over
30 other utilities in a lawsuit in the U.S. Court of Appeals for the District
of Columbia Circuit seeking assurance of the DOE's performance of its
contractual obligation to accept spent nuclear fuel and suspension of payment
to that agency pending such performance. In November 1997, the Court denied the
utilities' requested relief and held that the contracts between the utilities
and the DOE provide a potentially adequate remedy if the DOE failed to begin
disposal of spent nuclear fuel by January 31, 1998. However, the Court also
precluded the DOE from arguing that its delay in contracted performance was
"unavoidable."
The U.S. Congress is currently considering amendments to the Nuclear Waste
Policy Act to address certain of the issues which have arisen between the DOE
and the nuclear power industry regarding disposal of spent nuclear fuel as well
as the ongoing litigation against DOE. PPL Generation is unable to predict the
ultimate outcome of this proposed legislation or litigation.
GAS AND OIL
PPL EnergyPlus is responsible for procuring and managing the natural gas and
oil supply for our generation facilities.
PPL Generation's Martins Creek station Units 3 and 4 burn both oil and
natural gas. During 2000, we purchased all of our oil requirements for these
units on the spot market and all of our gas needs for these units under short
term agreements. At December 31, 2000, PPL Generation had no long-term
agreements to purchase oil or gas.
65
Many of our plants in development are gas-fired. We use long-term and
short-term supply and transportation contracts to provide fuel to our
generation facilities. We use firm and interruptible transportation contracts
on pipelines that provide us access to major production basins, including the
Gulf of Mexico. We have established trading relationships with a number of
counterparties. Our gas purchase agreements include both fixed-price and
index-price structures and we also use financial products to hedge fuel price
risk.
COMPETITION
Our businesses are highly competitive. The electric industry has experienced
a significant increase in the level of competition in the energy markets in
response to federal and state deregulation initiatives. See "Regulation" below.
We believe that as deregulation of the energy industry continues on both the
federal and state levels and retail energy markets are opened to new
participants and new services, competition will continue to be intense. In
addition to deregulation, competitive pressures have resulted from
technological advances in power generation and electronic communications, and
the energy markets have become more efficient.
The wholesale power markets which our operating generation companies serve
are highly competitive. Our competitors include regulated utilities, industrial
companies, non-utility generators and unregulated subsidiaries of regulated
utilities, many of whom have extensive and diversified operating expertise and
financial resources that are greater than those we possess. Our competitors may
operate power generation projects in regions where we have invested in
generation assets or develop more efficient generation projects thereby
increasing competition. Following the expiration of our various transition
power sales agreements, we will be increasingly making sales into the
competitive wholesale markets. We will principally compete on the basis of the
price of our products, although we will also compete to a lesser extent on the
basis of reliability and availability. The continuing deregulation of the
industry is likely to increase competition and may place downward pressure on
energy prices, which could adversely affect our results of operations.
We also face intense competition from a number of well-capitalized
participants in the non-utility power generation industry for the acquisition
and development of additional facilities. As a result, it may be more difficult
for us to compete for project sites and for equipment and in future bidding
situations, which could jeopardize our plans to acquire additional generation
capacity. In recent years, competition has increased as opportunities for new
projects are subject increasingly to competitive bidding as opposed to
negotiated transactions.
We also face competition in the markets for energy capacity and ancillary
services. As pricing information becomes increasingly available in the energy
trading and marketing business and as deregulation in the electricity
markets continues to accelerate, we anticipate that our trading, marketing and
risk management operations will experience greater competition. Primarily, our
trading, marketing and risk management operations compete with other energy
merchants based on the ability to aggregate supplies at competitive prices from
different sources and locations and to efficiently utilize transportation from
third-party pipelines and transmission from electric utilities. Competitors may
employ widely differing strategies in their fuel supply and power sales
contracts with respect to pricing, terms and conditions. Also, our operations
compete against other energy marketers on the basis of relative financial
position and access to credit sources. In particular, large competitors having
significant liquidity and other resources will compete with us for similar
business. This competitive factor reflects the tendency of energy customers,
wholesale energy suppliers and transporters to seek financial guarantees and
other assurances that their energy contracts will be satisfied.
REGULATION
Our operations are subject to extensive regulation by governmental agencies
in each of the jurisdictions in which we operate. Our domestic operations are
subject to energy, environmental, occupational health and safety and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of, and the use of
electric energy, capacity and related products, including
66
ancillary services from, our operations. In some instances, our regulatory
approvals and permits expire after a period of years and are then subject to a
renewal or relicensing procedure. Federal, state and local laws generally
require that a wide variety of permits and other approvals be obtained before
the commencement of construction or operation of an energy-producing facility
and that the facility then operate in compliance with these and other permits
and approvals. While we believe the requisite approvals for our existing
projects have been obtained and that our business is operated in substantial
compliance with applicable laws, we remain subject to a varied and complex body
of laws and regulations that both public officials and private parties may seek
to enforce.
Our international operations are subject to the jurisdiction of governmental
agencies in the countries in which our businesses operate. The degree of
regulation varies according to each country and may be materially different
from the regulatory regime in the United States. We believe that our operations
are in compliance in all material respects with all applicable laws and
regulations in the applicable foreign jurisdictions.
FEDERAL REGULATION
The SEC regulates holding companies that own subsidiaries that are electric
utilities pursuant to the Public Utility Holding Company Act of 1935, or PUHCA.
The FERC is an independent agency within the DOE that regulates the
transmission and wholesale sale of electricity in interstate commerce under the
authority of the Federal Power Act, or FPA. The FERC is also responsible for
licensing and inspecting private, municipal and state-owned hydroelectric
projects. The FERC determines whether a public utility qualifies for EWG status
under the Energy Policy Act of 1992 described below. The FERC also regulates
the sale of natural gas in interstate commerce. Nuclear generation operations
are regulated by the NRC.
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935; THE ENERGY POLICY ACT
Any corporation, partnership or other entity or organized group that owns,
controls or has the 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 registration with the SEC
and regulation under PUHCA, unless eligible for an exemption or unless an
appropriate application is filed with, and an order is granted by, the SEC
declaring it not to be a holding company. A registered public utility holding
company is required to limit its utility operations to a single integrated
utility system and to divest any other operations not functionally related to
the operation of that utility system. Approval by the SEC is required for major
financial commitments and other business dealings of the registered holding
company or its subsidiaries.
Regulations adopted under the Energy Policy Act of 1992 provide that EWGs
and foreign utility companies are not electric-utility companies under PUHCA.
All of our U.S. generation subsidiaries are EWGs, each of whose primary
business is the generation and sale at wholesale of electric energy. As EWGs,
the subsidiaries are not subject to regulation under PUHCA. As EWGs, the
subsidiaries are precluded from making any direct sales to retail customers, or
they will risk losing such exempt status and becoming electric-utility
companies under PUHCA. EWGs, however, are not exempt from regulation by the
FERC under the FPA or by state public utility commissions.
Loss of EWG or foreign utility company status could result in us becoming
subject to registration and regulation as a public utility holding company
under PUCHA. Loss of EWG or foreign utility company status on a retroactive
basis could lead to, among other things, fines and penalties. We do not expect
to engage in any activities that will subject us to registration or regulation
as a holding company under PUHCA.
FEDERAL POWER ACT
The FPA gives the FERC exclusive rate-making jurisdiction over wholesale
sales of electricity and transmission of electricity in interstate commerce.
The FERC regulates the owners of facilities used for the wholesale sale and
transmission of electricity in interstate commerce if those facilities are
owned by "public
67
utilities" under the FPA. The FPA also gives the FERC jurisdiction to review
certain transactions and numerous other activities of public utilities.
Under the FPA, a wholesale seller of electricity is subject to the FERC's
jurisdiction. Wholesale sellers of electricity are required to obtain the
FERC's acceptance of their rate schedules for wholesale sales of electricity.
Because we are selling electricity in the wholesale market, we are subject to
the FPA. PPL EnergyPlus and PPL Generation's EWG subsidiaries have authority
from the FERC to sell electric energy and capacity at market-based rates and to
sell, assign or transfer transmission rights and associated ancillary services.
Market-based rate authority enables us to price electric energy, capacity and
ancillary services based upon market conditions rather than upon our costs.
Under the market-based tariff, PPL EnergyPlus may also sell power purchased
from third parties.
The FERC has the authority to revoke our market-based rate authority on a
prospective basis if it subsequently determines that we possess excessive
market power. If we lost our market-based rate authority, we would be required
to obtain the FERC's acceptance of a cost-of-service rate schedule and would
become subject to the accounting, record-keeping and reporting requirements
that are imposed only on utilities with cost-based rate schedules. In addition,
when the FERC considers our request for market-based rate authority in
connection with a new acquisition or development project, it may include
generation owned or controlled by our stockholders in determining whether we
possess market power.
The FERC also regulates the rates, terms, and conditions for electricity
transmission in interstate commerce. Tariffs established under FERC regulations
give us access to transmission lines, which enable us to sell the energy we
produce into competitive markets for wholesale energy.
In April 1996, the FERC issued Order 888 requiring all public utilities to
file "open access" transmission tariffs that give wholesale generators, as well
as other wholesale sellers and buyers of electricity, access to transmission
facilities on a non-discriminatory basis. Some utilities are seeking permission
from the FERC to recover costs associated with stranded investments through
add-ons to their transmission rates. Order 888 was upheld by the FERC in March
1997 and affirmed in all material respects by the U.S. Court of Appeals for the
District of Columbia Circuit Court in June 2000. The United States Supreme
Court recently heard challenges to the Court of Appeals decision. There are
several implementation issues arising out of Order 888. These include issues
relating to power pool structures and transmission pricing.
The FERC subsequently issued (Orders 888-A, 888-B and 888-C) to clarify the
terms that jurisdictional transmitting utilities are required to include in
their open access transmission tariffs. The FERC also issued Order 889, which
required those transmitting utilities to abide by specified standards of
conduct when using their own transmission systems to make wholesale sales of
power, and to post specified transmission information, including information
about transmission requests and availability, on a publicly available computer
bulletin board. Although the pro forma tariff does not cover the pricing of
transmission service, Order 888 improved transmission access for independent
power producers.
The FERC is also encouraging, through its Order 2000, the voluntary
restructuring of transmission operations through the use of ISOs and RTOs. The
result of establishing these entities typically is to eliminate or reduce
transmission charges imposed by successive ("pancaked") transmission systems.
However, Order 2000 allows significant flexibility in the structure of these
organizations, and the full impact on us and our power marketing business is
uncertain at this time. In July 2001, the FERC issued a series of orders
centered around a vision of four (Northeast, Southeast, Mideast and West, with
Texas remaining separate) major RTOs. See "Our Selected Markets--Domestic
Market" for additional information.
The FPA also gives the FERC exclusive authority to license non-federal
hydroelectric projects on navigable waterways and federal lands. PPL Holtwood
operates two hydroelectric projects pursuant to licenses last reviewed by the
FERC in 1980, the Wallenpaupack Project and the Holtwood Project. The
Wallenpaupack
68
Project's license expires in 2004 and the Holtwood Project's license expires in
2014. PPL Holtwood also owns one-third of the capital stock of SHWPC, which
holds a project license which extends the operation of its hydroelectric plant
until 2030. In addition, PPL Montana holds eleven hydroelectric facilities and
one storage reservoir that are licensed by the FERC. When licenses expire, the
projects must either be relicensed or decommissioned. The FERC license for the
Mystic facility expires in 2009; the Thompson Falls and Kerr licenses expire in
2025 and 2035 respectively, and the license for the nine Missouri-Madison
facilities expire in 2040.
PPL Holtwood is working to have the Wallenpaupack Project relicensed.
Relicensing is generally a lengthy process and often takes from 4 to 10 years
to complete. Relicensing usually begins at least five years before the license
expiration date and the FERC issues annual licenses to permit a hydroelectric
facility to continue operations pending conclusion of the relicensing process.
We expect that the FERC will issue us renewal licenses for all of the
facilities with pending applications. Nonetheless, the possibility remains that
the FERC will not renew licenses for our projects, or will impose conditions
and affirmative obligations on our hydropower operations which could add
significant costs to, or actually curtail, our operations.
NUCLEAR REGULATION
PPL Susquehanna, a subsidiary of PPL Generation, is subject to the
jurisdiction of the NRC in connection with the operation of the two
nuclear-fueled generating units at its Susquehanna station. The license for
Unit 1 is scheduled to expire in 2022 and the license for Unit 2 is scheduled
to expire in 2024.
NATURAL GAS ACT
Our subsidiary, PPL Interstate Energy Company, is a natural gas and oil
pipeline company regulated by the PUC. In addition, some of the domestic
operating facilities that we own, operate or have investments in, are fueled by
natural gas, and more gas-fired facilities are under development and are
scheduled to begin operation in the near future. Under the Natural Gas Act, the
FERC has jurisdiction over the sale for resale, transportation and storage of
natural gas in interstate commerce. However, the FERC has determined that PPL
Interstate Energy Company operates solely on an intrastate basis.
OTHER
Congress has considered legislation that would require states to permit
retail competition. Other changes in federal energy regulation may occur in the
next several years. While we actively monitor developments to determine the
impact of such changes on our projects, operations and contracts, we cannot
predict the impact of such changes at this time.
STATE REGULATION
Many state utility commissions or state legislatures are already
considering, or have considered, whether to open the retail electric power
markets to competition. At present, many states have adopted some type of
"customer choice" plan to allow customers to choose their electricity
suppliers. Although state legislation and regulatory initiatives vary, many of
the state plans address the availability of market pricing, retail customer
choice, the separation of generation from transmission and distribution
services, and the recovery of "stranded costs."
State public utility regulatory commissions are responsible for approving
rates and other terms and conditions under which public utilities purchase
electric power from energy suppliers and sell retail electric power to
consumers. States may also assert jurisdiction over the siting, construction
and operation of our facilities, as well as the sale or other transfer of
assets.
69
PENNSYLVANIA. The Customer Choice Act, adopted in 1996, provided a
comprehensive electric industry restructuring plan that opened Pennsylvania's
retail electric market to competition, culminating in full retail choice as of
January 1, 2001. See "Business--Background" and Note 15 to the December 31,
2000 Financial Statements for a discussion of PPL Electric Utilities'
divestiture of its generation assets as part of its restructuring plan pursuant
to the Customer Choice Act.
PPL Electric Utilities is a PLR to customers who have not elected to choose
an alternative electricity supplier. PPL EnergyPlus has entered into power
sales agreements with PPL Electric Utilities under which PPL EnergyPlus is
obligated to supply PPL Electric Utilities with the amount of electricity it
may demand to serve its PLR retail load through 2009. See "Summary--Recent
Developments" for additional information.
Pennsylvania does not have a regulatory regime for wholesale generators in
the state. Therefore, we do not expect to be subject to regulation by the PUC
with respect to our generation of electricity in that state. However, if we
were to become subject to regulation by the PUC, additional costs would likely
be imposed on the operations of our assets located in Pennsylvania. PPL
EnergyPlus is subject to PUC regulation as an electric generation supplier, or
EGS.
MONTANA. As an EWG, we are currently exempt from energy regulation by the
MPSC. See "Summary--Recent Developments," "Business--Domestic Properties and
Projects--Montana" for a discussion of PPL Montana's agreements to supply
wholesale electricity to Montana Power and "Business--Legal Proceedings" for a
discussion of certain litigation against the MPSC.
MAINE. On May 29, 1997, Maine's Restructuring Act became effective, allowing
electric power to be sold directly to retail consumers by largely deregulated
power providers competing with one another. The delivery of power over
transmission and distribution lines continues to be a monopoly service provided
by a fully regulated utility. March 1, 2000, was the starting date for electric
competition.
The Restructuring Act required utilities to divest their generating assets,
and PPL Maine, LLC purchased most of the generating assets formerly owned by
Bangor Hydro Company. As a wholesale power producer and an EWG, PPL Maine is
not subject to Maine Public Utility Commission jurisdiction.
PPL Maine sells its output to PPL EnergyPlus which in turn sells to retail
customers. In order to sell to retail customers, PPL EnergyPlus must be
licensed as a competitive electricity provider, a designation which includes
marketers, brokers, aggregators and any other entity selling electricity to the
public at retail. The rules governing retail sales require that at least 30% of
a provider's generation source portfolio be comprised of certain renewable and
efficient resources and also define the generation sources that are considered
eligible. Hydroelectric projects of less than 100 MW of capacity meet the
renewable requirement. The rules also establish consumer protection regulations
that providers are required to observe when serving residential and small
commercial customers.
ARIZONA. As an EWG not engaged in any retail utility operations, we are
exempt from electric utility regulation by the Arizona Corporation Commission.
Generator siting certificates contain certain conditions governing facility
operations which require compliance during project life, but they are unrelated
to electric utility or marketing functions.
CONNECTICUT. Connecticut restructured its electric industry in 1998 pursuant
to Public Act 98-28. The Act provides for retail competition and the
divestiture of electric company generating assets. PPL Global, acting through
PPL Wallingford Energy LLC, has constructed an electric generating facility in
Wallingford, Connecticut. The facility was approved by the Connecticut Siting
Council and received environmental permits from the Connecticut Department of
Environmental Protection. As an EWG, the facility is not subject to regulation
by the Connecticut Department of Public Utility Control, or DPUC. However,
state law requires the facility to be registered with the DPUC. The facility
must also file annual 10-year load forecasts with the Siting Council.
70
ILLINOIS. The Electric Service Customer Choice and Rate Relief Law of 1997
provided a comprehensive restructuring plan that opened Illinois retail
electric market to competition and will culminate in full retail choice.
Illinois does not have a regulatory regime for wholesalers in the state.
Therefore, we do not expect to be subject to regulation by the Illinois
Commerce Commission. However, if we were to become subject to regulation by the
Illinois Commerce Commission, additional costs would likely be imposed on the
operations of our assets located in Illinois.
NEW YORK. In New York, all corporations and others owning, operating or
managing any "electric plant" are subject to the regulatory authority of the
New York Public Service Commission, or NYPSC, under the Public Service Law.
Those selling electricity to retail customers are subject to comprehensive
regulation of rates and charges, operations, accounting practices, enforcement,
investigation, safety, reliability, system improvements, construction,
securities issuances, reorganizations, property transfers, affiliated
transactions and other areas of operation.
Owners and operators of electric generating facilities who only sell
wholesale electricity have been consistently found to be subject to regulation
under a "lightened regulatory regime." Under this regime, our subsidiaries
owning or operating electric generation in New York would become subject to
provisions of the Public Service Law relating to enforcement, investigation,
safety, reliability, system improvements, construction, securities issuances,
reorganizations and property transfers. Transactions with affiliated interests
may be subject to review should the potential for the exercise of market power
exist. Moreover, with each addition of generating capacity under the control of
the same affiliated group of companies, the NYPSC will require a showing that
there is no potential for the exercise of market power. Should the potential
exist, the NYPSC may impose certain mitigation measures to minimize the
likelihood of the exercise of such market power.
WASHINGTON. Through Starbuck Power Company, L.L.C., or SPC, PPL Global
contemplates applying to the FERC for EWG status and market-based rate
authority for a proposed generating facility to be constructed near the Town of
Starbuck, Washington. The Washington Utilities and Transportation Commission,
or WUTC, regulates investor-owned electrical companies, but it does not
regulate the rates or facilities of EWGs. Neither the WUTC nor the Washington
State Legislature has sought to introduce broad-based retail competition into
the supply of electrical energy. SPC is seeking approval for facility siting
from the Washington Energy Facility Site Evaluation Council, which has the
authority to issue all state and local land use and environmental permits and
approvals required for construction and operation of the facility.
RETAIL SUPPLY IN ADJOINING STATES. PPL EnergyPlus has a PUC license to act
as an EGS in Pennsylvania. This license permits PPL EnergyPlus to offer retail
electric and gas supply to customers throughout Pennsylvania. PPL EnergyPlus
presently sells energy to industrial and commercial customers in Pennsylvania,
New Jersey, Delaware, Maine and Montana. PPL EnergyPlus is also licensed to
sell energy in Maryland and Massachusetts, and has filed an application for
such a license in New York.
FOREIGN REGULATORY MATTERS
UNITED KINGDOM
WPD (South West) and WPD (South Wales) are privatized regional electricity
distribution companies licensed to distribute, supply and, to a limited extent,
generate electricity in England and Wales. Each company is regulated under its
respective Public Electricity Supply License pursuant to which income generated
by the distribution business is subject to a price cap regulatory framework.
Distribution customers in England and Wales are connected to the
distribution system of the regional electricity companies and generally cannot
choose their electricity distributor. The Office of Gas and Electricity Markets
controls the revenues earned by each of WPD (South West) and WPD (South Wales)
in their respective distribution businesses by applying a price control
formula. This formula sets the maximum average price per
71
unit of electricity distributed. The elements used in the formula are generally
established for a five-year period and are subject to review by the regulator.
In December 1999, the regulator published final price proposals following his
review of the distribution revenue for distribution businesses. These proposals
represented a 20% reduction to distribution prices from April 1, 2000 for WPD
(South West) and a 26% reduction for WPD (South Wales), followed by a reduction
in real terms of 3% each year after April 1, 2000. This price control is
scheduled to operate until March 2005.
LATIN AMERICA
In the past decade, many governments in Latin America have taken steps to
encourage competition in the energy sector by restructuring, deregulating and
privatizing their electricity industries. We have been an active participant in
this process through our acquisition and operation of electricity assets.
In Brazil, Bolivia and Chile, retail electricity sales by our distribution
businesses are made pursuant to indefinite or long-term electricity
distribution and sale concession agreements. Each concession is granted on an
exclusive basis, which allows each business to charge its customers a tariff
for electric services that consists of three components: an energy expense
pass-through component, an operating cost component, and a capital-related
return component. Each component is established as part of the original grant
of the concession.
The electricity sales concessions provide for an annual adjustment to the
tariff based on several factors, including inflation increases, as measured by
different agreed upon indices. In certain countries, the pricing provisions of
the contract are linked to a portion of the tariff that reflects changes,
either entirely or in part, in exchange rates between the local currency and
the U.S. Dollar. At regular intervals, the concession grantor generally has the
authority to review the cost and capital-related return of the relevant
business to determine the inflation adjustment or other similar adjustment
factor, if any, to the operating cost component for the subsequent regular
interval. This review can result in an adjustment escalator that has a
positive, zero or negative value. This electricity market structure is often
referred to as "price-cap" regulation, because the investor's rate of return on
its equity is not directly subject to regulation.
In El Salvador, distribution companies are subject to annual registration
with the Registry of Electricity and Telecommunications. DelSur is a registered
electricity distributor in El Salvador. Distribution rates in El Salvador are
established annually by the General Superintendency for Electricity and
Telecommunications (SIGET). These rates are determined in three components:
. . energy rates, which are fixed annually based on the average spot
market prices for the preceding year;
. . rates related to the transmission and sale (commercialization) of
electricity, which are fixed annually based on real costs of the
distributor in the prior year; and
. . rates related to use of the national grid, which are fixed every 5
years.
Once the distribution rates are fixed, the distributor signs an agreement
with the SIGET confirming the arrangement.
OTHER
PPL EnergyPlus also has an export license to sell capacity and/or energy to
electric utilities in Canada. This export license allows PPL EnergyPlus to sell
either its own capacity and energy not required to serve domestic obligations
or power purchased from other utilities.
ENVIRONMENTAL MATTERS
PPL Generation's subsidiaries are subject to a number of present and
developing federal, regional, state and local laws and regulations with respect
to air and water quality, land use and other environmental matters. We believe
that we are in substantial compliance with applicable environmental laws and
regulations.
72
Current projections of capital expenditure requirements through the year
2005 to comply with the environmental regulations discussed below are included
in the table under "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Capital Expenditure Requirements" and are discussed
further in Note 13 to the December 31, 2000 Financial Statements. Additional
capital expenditures may be required in the future, in amounts that could be
material, as the result of changes in environmental regulations, the addition
of new facilities to our generation portfolio, or other factors which are not
now determinable.
AIR
GENERAL
The Clean Air Act deals in part, with acid rain, attainment of federal
ambient air quality standards and toxic air emissions. State agencies
administer the EPA's air quality regulations through the state implementation
plans, referred to as SIPs, and have concurrent authority to impose penalties
for non-compliance. Federal penalties can be up to $27,500 per violation per
day of violation at each facility. Requirements under the Clean Air Act are
imposed as permit limits in comprehensive permits issued to each generation
facility. Those permits contain specific emission limits and monitoring
requirements among other conditions.
SULFUR DIOXIDE AND NITROGEN OXIDE
Sulfur dioxide, or SO\\2,\\ and nitrogen oxide, or NO\\x,\\ are regulated at
all PPL Generation facilities under the acid rain program in Title IV of the
Clean Air Act. With respect to SO\\2\\, Title IV established a national cap
beginning in 1995 for some facilities and 2000 for others (Phases I and II,
respectively). The cap can be achieved through methods such as emission
controls, allowance purchases, fuel switching and unit retirements. The Montana
units have been allocated sufficient SO\\2\\ allowances to allow them to meet
the current Title IV acid rain cap indefinitely at current operational levels
without the need to purchase additional allowances. The Pennsylvania units have
not been allocated sufficient SO\\2\\ allowances and must rely upon banked or
purchased allowances and the use of low sulfur fuels, or must install scrubbers
in the future. We anticipate the need to install scrubbers at Montour in the
future, which will provide us with sufficient SO\\2 \\allowances.
NO\\x\\ is regulated under Title IV in two phases as well, with certain
facilities required to achieve the specified Phase I emission limits by 1995
and the more restrictive Phase II limits by 2000. The Martins Creek and
Brunner Island facilities in Pennsylvania are Phase I plants and comply with
Phase I limits. The Montour units in Pennsylvania and the Corette and Colstrip
facilities in Montana are Phase II plants. The Corette facility complies with
the Phase II limit. The Colstrip and Montour facilities deferred compliance
with the Phase II limits until 2009 by "opting in" to the Phase I program
early. Significant capital expenditures are not likely to be required at these
facilities to meet the Phase II limits in 2009.
In addition to the Title IV NO\\x\\ limits, the Pennsylvania units must
comply with NO\\x\\ limits imposed in states within the northeast ozone
transport region under the ozone nonattainment provisions of Title I of the
Clean Air Act. Under those provisions, the Pennsylvania units were required to
install low NO\\x\\ burners. In addition, Pennsylvania entered into a
memorandum of understanding with other northeast states implementing a NO\\x\\
cap and trade program commencing in 1999 that effectively capped NO\\x\\
emissions at the Pennsylvania units during May through June of each year to 57%
below their 1990 emissions. The Pennsylvania units comply with the cap.
Starting in 2003, the DEP is requiring further seasonal (May-June) NO\\x\\
reductions to 80% from 1990 levels. These further reductions are based on the
requirements of the memorandum of understanding and two EPA ambient ozone
initiatives: the September 1998 EPA SIP-Call (i.e., EPA's requirement for
states to revise their SIPs) issued under Section 110 of the Clean Air Act,
requiring reductions from 22 eastern states, including Pennsylvania; and the
EPA's approval of petitions filed by Northeastern states, requiring reductions
from sources in 12 Northeastern states and Washington D.C., including our
sources. We expect to achieve the 2003 NO\\x\\ reductions with the recent
installation of selective catalytic reduction, referred to as SCR, on the
Montour units and possibly SCR or selective non-catalytic reduction, referred
to as SNCR, on a Brunner Island unit.
73
The New Jersey Department of Environmental Protection and some New Jersey
residents have raised environmental concerns with respect to the Martins Creek
Plant in the context of the Lower Mt. Bethel project permit proceedings,
particularly with respect to SO\\2\\ emissions. PPL Martins Creek is discussing
these concerns with the New Jersey Department of Environmental Protection. The
cost of addressing these concerns is not now determinable, but could be
significant.
PARTICULATES AND REGIONAL HAZE
The EPA has established ambient air quality standards for coarse
particulates (i.e., particulates with a diameter greater than 10 microns).
States impose emission limits on sources to ensure that the ambient standard is
met. The Pennsylvania units periodically monitor their particulates emissions
through stack tests. All of these units have passed these tests. However, the
Montour units are installing new, larger electrostatic precipitators to enable
these units to burn a greater range of coals. The Montana units conduct annual
stack tests. Recently, two Colstrip units failed the particulates test. The
plant has taken corrective measures and has now demonstrated compliance.
In July 1997, the EPA 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 EPA by the
U.S. Court of Appeals for the District of Columbia Circuit Court in 1999. The
United States Supreme Court has reversed and remanded the case to the U.S.
Court of Appeals for the District of Columbia Circuit Court. Assuming the EPA
will ultimately implement these standards, we do not expect the revised ozone
standard to require substantial further NO\\x\\ reductions than those required
by the SIP-Call. The fine particulates standard could result in year-round
reductions in NO\\x\\ at SIP-call levels and further reductions in S0\\2\\
being required at some or all of our generation facilities by approximately
2012.
In 1999, the EPA also issued regional haze regulations that could result in
the imposition of additional NO\\x\\ and SO\\2\\ controls at some or all of our
facilities. The costs of such further NO\\x\\ and/or SO\\2\\ controls are not
now determinable but could be substantial.
HAZARDOUS AIR EMISSIONS
Under the Clean Air Act, the EPA has been studying the health effects of
hazardous air emissions from power plants and other sources and has determined
that mercury emissions must be regulated. In this regard, the EPA is expected
to develop regulations by 2004. The costs to our facilities could be
substantial, depending upon the specific regulatory requirements.
NEW SOURCE REVIEW
In 1999, the EPA initiated enforcement actions against several 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 commenced enforcement activities against other utilities. At
present, the EPA has suspended its enforcement activities pending an
interagency review of the "New Source" program. At this time we are unable to
predict whether any EPA enforcement actions will be brought with respect to any
of our plants. The EPA regional offices that regulate plants in Pennsylvania
(Region III) and Montana (Region VIII) have indicated an intention to issue
information requests to all utilities and power plants in their jurisdiction
and the EPA Region VIII office has issued such a request to PPL Montana's
Corette plant. PPL Montana has complied with these requests. We cannot
presently predict what, if any, action the EPA might take following our
responses to these information requests.
The EPA also proposed revising 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.
74
Compliance with any EPA revised regulations or enforcement action related to
new source requirements or any revised new source requirement could result in
additional capital and operating expenses in amounts which are not now
determinable, but which could be significant.
CARBON DIOXIDE
In December 1997, international negotiators reached agreement in Kyoto,
Japan to strengthen the 1992 United Nations Global Climate Change Treaty by
adding legally-binding greenhouse gas emission limits. This agreement--formally
called the Kyoto Protocol--would require the United States to reduce its
greenhouse gas emissions to 7% below 1990 levels by 2008-2012. Although the
Kyoto Protocol is unlikely to be ratified by the United States, some form of
carbon dioxide reductions will likely be required in the future. Compliance
under the agreement, if implemented, could result in increased capital and
operating expenses which are not now determinable but which could be
significant.
WATER
SURFACE WATER AND GROUNDWATER
The Federal Clean Water Act prohibits the discharge of any pollutant
(including heat), except in compliance with permits issued by the EPA or by
states delegated by the EPA to administer the permit program. Both Montana and
Pennsylvania are authorized to implement the permit program. The permits must
contain two types of limits: technology-based and water quality-based. The
technology-based limits are derived from standards established by the EPA for
various industrial categories. The EPA has developed such standards for the
steam electric industry. The water quality-based limits are those determined
necessary by the state to meet water quality standards established by the EPA.
The permit for the Montour plant contains stringent limits for iron
discharges. The results of a toxic reduction study show that additional water
treatment facilities or operational changes are needed at this station. A plan
for these changes has been submitted to the DEP. The cost of making these
changes is estimated to be under $5 million.
In 2000, the EPA also significantly tightened the water quality standard for
arsenic. However, the EPA has now withdrawn the new standard in order to
further study the matter. A tightened standard may require our subsidiaries to
further treat wastewater and/or take abatement action related to groundwater
degradation at several power plants, the cost of which is not now determinable,
but could be significant.
Both Pennsylvania and Montana have laws prohibiting groundwater degradation.
Groundwater protection measures at our facilities include coal pile liners
beneath all or most of the coal pile at all stations (other than Colstrip in
Montana and Martins Creek in Pennsylvania), no active fly ash settling ponds
(except at Martins Creek in Pennsylvania and under limited circumstances at
other Pennsylvania stations), and networks of groundwater monitoring wells at
each station.
More detailed descriptions of environmental issues related to groundwater
contamination at Pennsylvania generation facilities is provided below under
"Pennsylvania Groundwater/Surface Water Protection Issues." Projected capital
expenditures for PPL Montana's facilities and more detailed descriptions of
environmental issues related to Montana facilities are noted below under
"Montana Environmental Site Assessments." Capital expenditures at both Montana
and Pennsylvania could be required beyond the year 2005 in amounts which are
not now determinable but which could be significant. Actions taken to correct
groundwater degradation, to comply with environmental regulations and to
address waste water control, are also expected to result in increased operating
costs in amounts which are not now determinable but which could be significant.
Groundwater and surface water protection is also imposed at the coal mining
and coal processing facilities in Pennsylvania. Pursuant to the Surface Mining
and Reclamation Act of 1977, the United States Office of
75
Surface Mining, or OSM, has adopted effluent guidelines which are applicable to
these facilities. The EPA and the OSM limitations, guidelines and standards
also are enforced through the issuance of water discharge permits. In
accordance with the provisions of the Clean Water Act and the Reclamation Act
of 1977, the EPA and the OSM have authorized the states to implement the permit
program. A more detailed discussion of environmental issues related to
groundwater and surface water protection at these facilities is provided under
"Pennsylvania Groundwater/Surface Water Protection Issues" below.
In addition to the water discharge limits discussed above, the EPA has
proposed requirements for new or modified water intake structures to protect
fish from entrainment and impingement. These regulations will affect where
generation facilities are built, will establish intake design standards, and
could lead to requirements for cooling towers at new power plants. These
proposed regulations are expected to be finalized during 2001. The rule could
require new or modified cooling towers at one or more stations owned by our
subsidiaries. Another new rule, expected in 2003, will address existing
structures. Each of these rules could impose significant costs on our
subsidiaries, which are not now determinable.
WATER RIGHTS
We believe that the water rights associated with the Montana hydroelectric
generation facilities are sufficient to allow us to continue to operate these
facilities. The Montana Water Court is currently adjudicating most water rights
in Montana with a priority date before July 1, 1973; however, we have no
reasons to believe that our rights would be altered by that process in any way
that would materially affect operation of our generation facilities.
Water use in Pennsylvania is primarily regulated by the Delaware River Basin
Commission, referred to as the DRBC, or the Susquehanna River Basin Commission,
referred to as the SRBC, depending upon the location of the facility. We do not
currently anticipate material increases in capital or operating costs resulting
from DRBC or SRBC actions. However, the Commonwealth of Pennsylvania is
contemplating water use legislation. Such legislation, if enacted, could impose
material additional costs on our subsidiaries in Pennsylvania.
SOLID AND HAZARDOUS WASTE
The energy industry typically generates a range of solid wastes, including
hazardous wastes. The handling and disposal of such wastes are strictly
regulated under the federal Resource Conservation and Recovery Act, or RCRA,
and state regulations. Under the Bevill Amendment to RCRA, wastes from
coal-burning generation facilities were temporarily classified as non-hazardous
for purposes of regulation, which meant that these wastes could be exempt from
the significantly more stringent (and costly) regulatory requirements for
hazardous wastes. The EPA, however, was directed by statute to determine
whether these wastes should be regulated as hazardous wastes. The EPA 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 EPA or the states could seek to
regulate coal combustion wastes as hazardous wastes in the future. Any such
regulations could have a significant cost impact on facilities owned by our
subsidiaries.
Liability for past waste disposal is imposed by the Comprehensive
Environmental Response Compensation and Liability Act and equivalent state
laws. These laws require past and present owners of contaminated sites and
generators of any hazardous substances found at a site to clean-up the site or
pay the EPA or the state for the costs of clean-up. The generators and past
owners can be liable even if the generator contributed only a minute portion of
the hazardous substances at the site. Present owners can be liable even if they
contributed no hazardous substances to the site.
76
These laws also provide for federal and state governmental agencies to seek
compensation from the responsible parties for the lost value of damaged natural
resources. These agencies may file such compensation claims against the parties
held responsible for clean-up of such sites. Such natural resource damage
claims could result in material additional liabilities for our subsidiaries.
In 1995, one of our affiliates, PPL Electric Utilities, entered into a
consent order with the DEP to address a number of potentially contaminated
sites, including sites now owned by our subsidiaries. As of December 31, 2000,
the estimated cost of addressing our Pennsylvania sites including those under
the consent order was approximately $450,000. Future clean-up or remediation
work at sites currently under review, or at sites not currently identified, may
result in material additional operating costs for us that cannot be estimated
at this time. See "Montana Environmental Site Assessments" below for a
discussion of contamination issues related to facilities in Montana.
PENNSYLVANIA GROUNDWATER/SURFACE WATER PROTECTION ISSUES
COAL MINE SITES
Certain of our subsidiaries previously owned three sites at which coal
mining or coal handling took place, that are now owned by third parties. As
noted in the discussion under "Solid and Hazardous Waste" above, our
subsidiaries may be liable for contamination at sites they owned in the past.
In addition, our subsidiaries currently own three coal mine sites at which coal
mining or coal handling took place in the past. Potential environmental issues
that have been identified for coal mine sites include coal refuse pile releases
to groundwater or surface water and mine releases to groundwater or surface
water. The costs of addressing these issues could be substantial.
COMBUSTION TURBINE SITES
Certain of our subsidiaries own various combustion turbine power generation
sites, several of which had or may still have petroleum contamination in the
soil or groundwater as a result of past leaks or spills from storage tanks.
Significant soil and/or groundwater remediation has been conducted at some of
these sites. Other sites could require soil and/or groundwater remediation if
contamination is found. The cost of such remedial actions at these sites could
be substantial.
POWER PLANT SITES
The most significant environmental issues identified to date at our
Pennsylvania power plants include releases of contaminants from the ash basins,
coal piles and pyritic mill rejects; potential releases of oils containing
polychlorinated biphenyls, or PCBs, from electric equipment; and releases of
oils from storage tanks and associated underground piping at the plants.
Groundwater monitoring at several of our Pennsylvania power plants indicates
that the quality of groundwater has been impacted by releases from the basins,
the coal piles, the tanks and/or the underground piping. A number of remedial
actions have been taken at some of our Pennsylvania power plants to address
such impacts, including installation of slurry walls and/or caps at ash basins,
installation of liners at the coal piles and operation of oil recovery systems.
Additional actions could be required at our Pennsylvania power plants, the
costs of which could be substantial.
In addition, one of our subsidiaries operates the Susquehanna Nuclear Plant
in Pennsylvania. Issues related to the Susquehanna nuclear plant are discussed
in the section below entitled "Low-Level Radioactive Waste."
MONTANA SUPREME COURT DECISION
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 PPL Montana of any such changes in laws or
regulations or any such increase in legal actions are not currently
determinable, but could be significant.
77
MONTANA ENVIRONMENTAL SITE ASSESSMENTS
As part of the transfer of the Montana assets, Montana Power retained an
environmental consultant to conduct environmental site assessments at the
Montana plants. Montana Power's consultant identified no material issues with
respect to the Corette facility or any of the hydroelectric facilities. The
Colstrip facility has a complex system of ponds used for the discharge of plant
effluents and coal ash. According to Montana Power, seepage from the ponds had
resulted in impacts to groundwater over various portions of the Colstrip
facility site. Montana Power installed groundwater capture systems to mitigate
the environmental impacts. We do not currently expect PPL Montana's share of
remediation costs to address these groundwater impacts to be material.
Since acquiring the leased Colstrip assets and becoming the operator, we
have received three violation letters from the Montana Department of
Environmental Quality, or DEQ. The DEQ issued a January 27, 2000 letter
regarding a September 1999 transformer cooling oil spill that occurred while
Montana Power 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 DEQ 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 DEQ 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. We estimate that our share of the
costs for repair of the saddle dam could range from $75,000 to $2.25 million.
Under the acquisition agreement with Montana Power, PPL Montana is
indemnified by Montana Power for any pre-acquisition environmental liabilities.
However, this indemnification is conditioned on certain circumstances that can
result in PPL Montana and Montana Power sharing in certain costs within limits
set forth in the agreement.
LOW-LEVEL RADIOACTIVE WASTE
Under federal law, each state is responsible for the disposal of low-level
radioactive waste generated in that state. States may join in regional compacts
to jointly fulfill their responsibilities. The states of Pennsylvania,
Maryland, Delaware and West Virginia are members of the Appalachian States
Low-Level Radioactive Waste Compact. Efforts to develop a regional disposal
facility in Pennsylvania were suspended by the DEP in 1998. The Commonwealth
retains the legal authority to resume the siting process should it be
necessary. Low-level radioactive waste resulting from the operation of
Susquehanna nuclear plant in Pennsylvania is currently being sent to Barnwell,
South Carolina for disposal. In the event this or other emergent disposal
options become unavailable or no longer cost-effective, the low-level
radioactive waste will be stored on-site at Susquehanna. We cannot predict the
future availability of low-level waste disposal facilities or the cost of such
disposal.
EMPLOYEE RELATIONS
As of December 31, 2000, we and our subsidiaries had 7,196 full-time
employees. This total included 2,398 in PPL Generation; 1,697 in PPL EnergyPlus
(including the mechanical contractors); 45 in PPL Global; and 3,056 in several
Central and South American electric companies controlled by PPL Global.
Approximately 31% of our domestic workforce, or 1,298 employees, are members
of labor unions, with three IBEW locals representing nearly 1,290 employees.
The bargaining agreement with the largest union was negotiated in 1998 and
expires in May of 2002. In 2001, PPL Montana reached a new three-year contract
with one IBEW local and a four-year contract with another IBEW local. PPL
Montana is also currently negotiating with the Teamsters for a new agreement,
as the existing agreement expires in 2001.
78
LEGAL PROCEEDINGS
We are not currently involved in any legal proceedings the outcome of which
we expect would have a material adverse effect on our financial condition or
results of operations.
See "Business--Fuel Management and Procurement" for information concerning a
lawsuit against the DOE for failure of that agency to perform certain
contractual obligations.
Pursuant to changes in the Public Utility Realty Tax Act enacted in 1999,
referred to as PURTA, certain of our subsidiaries have filed a number of tax
assessment appeals in various Pennsylvania counties where our generation plants
are located. These appeals challenge existing local tax assessments, which now
furnish the basis for payment of the PURTA tax on our properties. Also, as of
January 1, 2000, generation facilities are no longer taxed under PURTA, and
these local assessments will be used directly to determine local real estate
tax liability for our power plants. In July 1999, our predecessors filed
retroactive appeals for tax years 1998 and 1999, as permitted by the new law,
as well as prospective appeals for 2000, as permitted under normal assessment
procedures. Additional prospective appeals were filed in 2000 for the 2001 tax
year. It is anticipated that assessment appeals will now be an annual
occurrence.
Hearings on the pending appeals were held by the boards of assessment
appeals in each county, and decisions have now been rendered by most counties.
To the extent the appeals were denied or we were not otherwise satisfied with
the results, we filed further appeals from the board decisions with the
appropriate county Courts of Common Pleas.
Of all the pending proceedings, the most significant appeal concerns the
assessed value of the Susquehanna nuclear station. The county assessment of the
Susquehanna station indicated a market value of $3.9 billion. Based on this
value, the annual local taxes for the Susquehanna station would have been about
$70 million. However, we were able to reach a settlement with the local taxing
authorities in late December 2000, for tax years 2000 and 2001. This settlement
will result in the payment of annual local taxes of about $3 million. We and
the local taxing authorities also reached a settlement concerning the 1998 and
1999 tax years which, if effectuated, would not result in any additional PURTA
tax liability. This portion of the settlement with the local tax authorities is
subject, however, to the outcome of claims asserted by certain intervenors
which are described below.
In August 2000, over our objections, the court permitted Philadelphia City
and County, the Philadelphia School District and the Southeastern Pennsylvania
Transportation Authority, which we refer to collectively, as the "Philadelphia
parties", to intervene in the case. The Philadelphia parties have intervened
because they believe a change in the assessment of the plant will affect the
amount they would collect under PURTA for the tax years 1998 and 1999. As part
of the change in law, the local real estate assessment determines what the 1998
and 1999 PURTA payments by PPL will be. In November 2000, the Philadelphia
parties submitted their own appraisal report, which indicates that the taxable
fair market value of the Susquehanna station under PURTA for 1998 and 1999 is
approximately $2.3 billion. Based on this appraisal, we would have to pay up an
extra $213 million in PURTA taxes for tax years 1998 and 1999.
Our appeal of the Susquehanna station assessment for 1998 and 1999 is still
pending in the Luzerne County Court of Common Pleas; trial commenced in
December 2000, and is continuing. As a result of these proceedings and
potential appeal, a final determination of market value and the associated tax
liability for 1998 and 1999 may not occur for several years.
In the other assessment appeals pending in county courts, the local
authorities have assessed our generation plants at an aggregate market value
amount of about $311 million for tax year 2000, for a total tax liability of
about $5.2 million. We have estimated the aggregate market value of these
plants at about $26 million for tax year 2000, for a total tax liability of
about $460,000. As at the Susquehanna station, the school districts involved in
these proceedings have issued interim tax bills at levels which are disputed by
us. Final determinations of market value and associated tax liability in these
proceedings may not occur for several years.
79
In June 2001, the MPSC issued an order (MPSC Order) in which it found that
Montana Power must continue to provide electric service to its customers at
tariffed rates until its transition plan under the Montana Electricity Utility
Industry Restructuring and Customer Choice Act is finally approved, and that
purchasers of generating assets from Montana Power must provide electricity to
meet Montana Power's full load requirements at prices to Montana Power that
reflect costs calculated as if the generation assets had not been sold. PPL
Montana purchased Montana Power's interest in two coal-fired plants and 11
hydroelectric units in 1999. In July 2001, PPL Montana filed a complaint
against the MPSC with the U.S. district Court in Helena, Montana, challenging
the MPSC Order. In its complaint, PPL Montana asserted, among other things,
that the Federal Power Act preempts states from exercising regulatory authority
over sale of electricity in wholesale markets, and requested the court to
declare the MPSC action preempted, unconstitutional and void. In addition, the
complaint requested that the MPSC be enjoined from seeking to exercise any
authority, control or regulation of wholesale sales from PPL Montana's
generating assets.
At this time, PPL Energy Supply and PPL Montana cannot predict the outcome
of the proceedings related to the MPSC Order, what actions the MPSC, the
Montana Legislature or any other governmental authority may take on these or
related matters, or the ultimate impact on PPL Energy Supply and PPL Montana of
any of these matters.
In an unrelated matter, in July 2001, PPL Montana filed an action in state
court and a responsive pleading in federal court, both related to a breach of
contract by Energy West Resources, Inc. (Energy West), a Great Falls,
Montana-based energy aggregator. In the federal action, PPL Montana requested
that the court refrain from issuing a preliminary injunction and lift a
temporary restraining order that had been issued in July 2001, prohibiting PPL
Montana from seeking to terminate the contract under which it supplies energy
to Energy West. In the state action, PPL Montana is seeking a judgment that
Energy West violated the terms of the supply contract and should pay damages of
at least $7.5 million. Subsequently, in July 2001, the federal court judge
dissolved the temporary restraining order and stayed all proceedings in the
case pending resolution by the FERC of a request by PPL Montana to terminate
the contract between PPL Montana and Energy West. On September 14, 2001, the
FERC issued an order rejecting PPL Montana's request to terminate the contract.
The FERC order was without prejudice, and PPL Montana may refile its notice of
termination after the conclusion of the court proceedings. All litigation in
this matter has been consolidated in the U.S. District Court for the District
of Montana, Great Falls Division, and is proceeding in that forum. PPL Energy
Supply and PPL Montana cannot predict the ultimate outcome of these proceedings.
On April 28, 2000, three employees at PPL Montana's 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 PPL Montana and
jointly owned with Puget Sound Energy, Inc. On May 15, 2000, the injured
employees and their spouses filed litigation for their injuries in state
district court against Montana Power. PPL Montana has been named as a party
defendant to the pending litigation, but it is too early to predict the
likelihood of plaintiffs establishing any liability on the part of PPL Montana
for the injuries of the plaintiffs or to estimate the scope of any potential
damages award against PPL Montana.
Litigation arising out of the California electricity supply situation has
been filed at the FERC and in California courts against sellers of energy to
the California ISO. The plaintiffs and intervenors in these proceedings allege
abuses of market power, manipulation of market prices, unfair trade practices
and violations of state antitrust laws, 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 attorney's fees. Certain of our subsidiaries have intervened
in the FERC proceedings in order to protect their interests, but have not been
named as defendants in any of the court actions. Attorneys general in several
western states, including California, have begun investigations related to the
electricity supply situation in California and other western states. The FERC
has determined that all sellers of energy in the California markets should be
subject to refund liability for the period beginning October 2, 2000 through
June 20, 2001 and has
80
initiated an evidentiary hearing concerning refund amounts. The FERC also is
considering whether to order refunds for sales made in the Pacific Northwest,
including sales made by our subsidiaries. The FERC Administrative Law Judge
assigned to this proceeding has recommended that no refunds be ordered for
sales into the Pacific Northwest. The FERC presently is considering this
recommendation. We cannot predict whether or the extent to which any of our
subsidiaries will be the target of any governmental investigation or named in
these lawsuits, refund proceedings or other lawsuits, the outcome of any such
proceedings or whether the ultimate impact on PPL Energy Supply or its
subsidiaries of the electricity supply situation in California and other
western states will be material.
On August 16, 2001, a purported class-action lawsuit was filed by a group of
shareholders of Montana Power against Montana Power, the directors of Montana
Power, certain unnamed advisors and consultants of Montana Power, and PPL
Montana. The plaintiffs allege, among other things, that Montana Power was
required to, and did not, obtain shareholder approval of the sale of Montana
Power's generation assets to PPL Montana in 1999. Although most of the claims
in the complaint are against Montana Power, its board of directors, and its
consultants and advisors, one claim is asserted against PPL Montana. That claim
alleges that PPL Montana was privy to and participated in a strategy whereby
Montana Power would sell its generation assets to PPL Montana without first
obtaining Montana Power shareholder approval, and that PPL Montana has made net
profits in excess of $100 million as the result of this alleged illegal sale.
The complaint requests that the court impose a "resulting and/or constructive
trust" on both the generation assets themselves and the alleged $100 million of
net profits realized by PPL Montana from such assets. The complaint also seeks
10% per annum interest on the amounts subject to the trust. PPL Montana is
unable to predict the outcome of this matter.
81
MANAGEMENT
We are a Delaware limited liability company and currently have no employees
other than our officers. Our officers have not received and currently receive
no compensation from us for the services they provide to us or for any
transaction between us and any of our affiliates. We are managed by our board
of managers under the terms of our Limited Liability Company Agreement, dated
as of March 20, 2001. PPL Corporation controls PPL Energy Funding as its sole
stockholder, and PPL Energy Funding, in turn, controls us as our sole member.
PPL Energy Funding 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
a successor is elected and qualified or until resignation or removal, and each
of our officers serves at the discretion of the board of managers.
OUR BOARD OF MANAGERS AND EXECUTIVE OFFICERS/(1) /
The following table sets forth information concerning our board of managers
and executive officers and the Presidents of our significant operating
subsidiaries as of the date of this prospectus.
NAME AGE POSITION
---- --- --------
William F. Hecht..... 58 President and Member of the Board of Managers
John R. Biggar....... 57 Vice President and Member of the Board of Managers
James E. Abel........ 51 Treasurer and Member of the Board of Managers
Joseph J. McCabe..... 51 Controller and Member of the Board of Managers
Lawrence E. De Simone 54 Member of the Board of Managers
Robert J. Grey....... 51 Member of the Board of Managers
Paul T. Champagne.... 43 President of PPL EnergyPlus
James H. Miller...... 53 President of PPL Generation
Roger L. Petersen.... 50 President of PPL Global
- --------
/(1)/Messrs. Champagne, Miller and Petersen have been designated executive
officers by virtue of their positions at our subsidiaries.
William F. Hecht has been our President and a member of our board of
managers since March 2001. Mr. Hecht is also Chairman, President and Chief
Executive Officer and a director of PPL Corporation and has been since 1995,
when PPL Corporation was formed. Mr. Hecht joined PPL Electric Utilities 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 Electric
Utilities' board of directors. Mr. Hecht was elected President and Chief
Operating Officer of PPL Electric Utilities in 1991. Mr. Hecht is a director of
Dentsply International, Inc. and RenaissanceRe Holdings Ltd. 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.
John R. Biggar has been Vice President of PPL Energy Supply and a member of
our board of managers since March 2001. Mr. Biggar is also Executive Vice
President and Chief Financial Officer of PPL Corporation, and effective October
1, 2001, Mr. Biggar became a director of PPL Corporation. Before being named to
his current position in 2001, Mr. Biggar served two years as Senior Vice
President and Chief Financial Officer of PPL Corporation and 14 years as Vice
President--Finance of PPL Electric Utilities. Mr. Biggar has also been a
director of PPL Electric Utilities since July 2000. He started his career in
1969 in the legal department of PPL Electric Utilities, 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 Electric Utilities. 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.
82
James E. Abel has been Treasurer of PPL Energy Supply and a member of our
board of managers since March 2001. Mr. Abel is also Vice President--Finance
and Treasurer of PPL Corporation. Mr. Abel joined PPL Electric Utilities in
1972, was named Manager--Treasury in 1984, served as Manager--Corporate Audit
Services from 1995-1996 and has served as Treasurer since 1996. He holds a
bachelor of science degree in accounting and a master of business
administration degree from Lehigh University. Mr. Abel is a Certified
Management Accountant and a Certified Financial Planner.
Joseph J. McCabe has been our Controller since March 2001, and a member of
our board of managers since August 2001. Mr. McCabe is also Vice President and
Controller of PPL Corporation and has been since 1995. Mr. McCabe started his
career with PPL as Controller in 1994. Prior to joining PPL Corporation, Mr.
McCabe served in various positions at Deloitte & Touche for 21 years. Mr.
McCabe holds a bachelor's degree from Seton Hall University, where he has also
done post-graduate study. He completed the executive program at Northwestern
University's Kellogg Graduate School of Management.
Lawrence E. De Simone became a member of our board of managers, and
Executive Vice President--Supply of PPL Corporation effective October 1, 2001.
Prior to his appointment as Executive Vice President--Supply of PPL
Corporation, he served as President of PPL EnergyPlus beginning in November
1998. Mr. De Simone also has been a director of PPL Electric Utilities since
July 2000. Prior to joining PPL EnergyPlus, he was Senior Vice
President--Energy Services at Virginia Power Company and President of Central &
South West Corp.'s energy services and telecommunications operations as well as
its Vice President for Strategic Planning. Mr. De Simone earned a bachelor of
arts degree in economics from Claremont McKenna College and a doctorate in
business administration from the University of California at Berkeley.
Robert J. Grey has been a member of our board of managers since March 2001.
Mr. Grey is Senior Vice President, General Counsel and Secretary of PPL
Corporation. Mr. Grey joined PPL Corporation in 1995 as Vice President, General
Counsel and Secretary and was promoted to his current position in March 1996.
Mr. Grey has also been a director of PPL Electric Utilities since July 2000.
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.
Paul T. Champagne became President of PPL EnergyPlus effective October 1,
2001. In addition to his position at PPL EnergyPlus, he has been a director of
PPL Electric Utilities since July 2000. Prior to his appointment as President
of PPL EnergyPlus, he was President of PPL Global since 1999 and Vice President
and Senior Development Officer of PPL Global since 1995. Prior to joining PPL
Global in 1995, he served in several business development positions at Edison
Mission Energy Company (formerly Mission Energy Company), including Midwest
regional manager. He also served as a research engineer at the Research
Triangle Institute, which provided consulting services to the Electric Power
Research Institute. Mr. Champagne earned a B.S. in chemical engineering and
completed master's course work in mechanical engineering at the University of
Illinois.
James H. Miller has been President of PPL Generation and a director of PPL
Electric Utilities since February 2001. Prior to that time, he served as
Executive Vice President of USEC, Inc., President of ABB Environmental Systems,
President of UC Operating Services, President of ABB Resource Recovery Systems
and Plant Manager, Delmarva Power and Light Co. Mr. Miller holds a bachelor of
science degree in electrical engineering from the University of Delaware and
served in the U.S. Navy nuclear program.
Roger L. Peterson became President of PPL Global and a director of PPL
Electric Utilities effective October 1, 2001. Prior to his appointment as
President of PPL Global, he served as President of PPL Montana beginning in
1999. Mr. Petersen also served as Chief Operating Officer of PPL Global from
1995 to 1999. Prior to joining PPL Global, he served as Regional Vice
President--North American Operations for Edison Mission Energy Company
(formerly Mission Energy Company). He also worked with Fluor Engineers and
Constructors as a
83
project manager for U.S. and international projects. Mr. Petersen earned a B.S.
in mechanical engineering from South Dakota State University, an M.S. in
engineering from California Polytechnical Institute and a business management
degree from the University of California at Los Angeles.
There are no family relationships among any of the above-named members of
our board of managers or executive officers, or any arrangement or
understanding between any members of our board of managers or executive
officers and any other person pursuant to which such member or officer was
selected.
Each of our officers and members of our board of managers listed above is
currently an officer, director or employee of PPL Corporation or an affiliate
of PPL Corporation and receives compensation from PPL Corporation or an
affiliate. In addition, each of our officers and members of our board of
managers participates in employee benefit plans and arrangements sponsored by
PPL Corporation or an affiliate. See Notes 10 and 11 to the December 31, 2000
Financial Statements. We are not a party to any agreement with PPL Corporation
or its affiliates governing the compensation paid to our officers, members of
our board of managers or employees. These persons are paid by PPL Corporation
or its affiliates, as applicable, in the normal course of their employment with
the relevant party. No cash or non-cash compensation is currently proposed to
be paid in the current calendar year by us to any of the officers or members of
our board of managers listed above.
OWNERSHIP OF OUR MEMBERSHIP INTERESTS
All of our membership interests are owned by PPL Energy Funding, a direct,
wholly-owned subsidiary of PPL Corporation. There is no public trading market
for our membership interests. None of our officers or members of our board of
managers beneficially own any of our equity interest.
84
CERTAIN 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.
PPL Corporation is not obligated to provide any loans, equity contributions or
other funding to us.
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 noteholders 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 noteholders.
In the future, PPL Corporation or its subsidiaries may compete with us for
business opportunities.
We and our subsidiaries may from time to time enter into contracts or other
business relationships with PPL Corporation or its affiliates. For example, our
executive management and many administrative services are provided by PPL
Services Corporation. In addition, our subsidiaries have incurred intercompany
borrowings to meet their capital and operating needs and we expect to continue
to do so.
The following describes our material agreements and arrangements with PPL
Corporation and affiliates:
REALIGNMENT
On July 1, 2000, PPL Corporation and PPL Electric Utilities completed a
corporate realignment in order to effectively separate PPL Electric Utilities'
regulated transmission and distribution businesses from its generation
businesses and to better position the companies and their affiliates in a new
competitive marketplace. As part of the realignment, PPL Electric Utilities'
generation assets and associated liabilities were transferred to PPL Generation
and its wholesale and retail power marketing assets and associated liabilities
were transferred to PPL EnergyPlus. PPL Global also transferred its domestic
electric generation subsidiaries to PPL Generation. In May 2001, PPL Energy
Funding contributed its interests in PPL Generation, PPL EnergyPlus and PPL
Global to PPL Energy Supply. See Notes 1 and 15 to the December 31, 2000
Financial Statements for additional information.
NUG CONTRACTS
In connection with the realignment, PPL EnergyPlus entered into a contract
with PPL Electric Utilities under which PPL Electric Utilities has agreed to
sell electricity purchased under contracts with non-utility generators, or
NUGs, to PPL EnergyPlus. Under the contract, PPL Electric Utilities purchases
electricity from the NUGs at contractual rates and then sells the electricity
at the same price to PPL EnergyPlus.
PLR CONTRACTS
PPL EnergyPlus has a full requirements contract to provide PPL Electric
Utilities with electricity sufficient for PPL Electric Utilities to meet its
PLR obligations under the Pennsylvania Customer Choice Act, through the end of
2001, at the pre-determined capped rates that PPL Electric Utilities may charge
its PLR customers, regardless of the prevailing market price. As part of a
settlement order of the Pennsylvania Public Utility Commission, or PUC, PPL
Electric Utilities is required to provide this electricity at pre-determined
"capped" rates through 2009 to customers not choosing an alternate electric
supplier. While rates for generation supply vary by customer class, the
settlement order provides for average rates ranging from 4.16 cents per kWh in
2001, increasing to 5.02 cents per kWh in 2009. In June 2001, PPL Energy Supply
entered into a new contract to provide electricity to PPL Electric Utilities
sufficient for it to meet its PLR obligation from 2002 through 2009, at the
pre-determined capped rates PPL Electric Utilities is entitled to charge its
customers during this period. Under the new contract, PPL EnergyPlus received
an up-front $90 million payment to offset differences between the revenues
expected under the pre-determined rates and projected market prices through the
life of the supply agreement (as projected by PPL EnergyPlus when it submitted
its bid). See "Recent Developments."
85
SERVICES AGREEMENT
PPL Services Corporation, a subsidiary of PPL Corporation, provides various
business services, such as executive management, administration, accounting,
finance, legal, communications, purchasing, billing information systems,
corporate secretarial, human resources, insurance and other similar types of
services, to PPL Corporation and its affiliates, including us. The payment of
salaries, the cost of the services provided by PPL Services Corporation and
other general corporate expenses incurred by PPL Services Corporation in
connection with the provision of these services to us are directly charged to
us at cost or allocated to us using methods that we believe are reasonable.
TRANSMISSION SERVICES
We purchase transmission services from our affiliate, PPL Electric
Utilities, at prices and terms set under FERC open-access tariffs.
INTERCOMPANY LOANS
PPL Corporation and PPL Capital Funding, Inc. provide funding for us and our
subsidiaries. Such funding includes loans that are due on demand and interest
is charged based on PPL Capital Funding's short-term borrowing rate. In
addition, PPL Energy Supply has notes receivable from its affiliates, including
PPL Corporation. These notes were issued in connection with PPL Corporation's
overall cash management strategies. Notes receivable from affiliated companies
and short-term debt payable to affiliated companies at September 30, 2001 were
$1.4 billion and $0, respectively.
We also have a 364-day revolving credit facility with PPL Capital Funding
and PPL Corporation under which we have agreed to lend PPL Capital Funding up
to $800 million in order to enhance liquidity and as a credit back-stop to PPL
Capital Fundings's commercial paper program. At September 30, 2001, there were
no borrowings under this facility. We anticipate that PPL Capital Funding will
terminate its commercial paper facility and that this credit facility will be
terminated when we establish a commercial paper program at PPL Energy Supply,
currently anticipated to occur later this year.
TAX SHARING ARRANGEMENTS
We join PPL Corporation and its subsidiaries in filing a consolidated
federal income tax return. We also join PPL Corporation and its subsidiaries in
filing consolidated state income tax returns in some states and contribute to
the state income tax liability in other states. Pursuant to our tax sharing
arrangements, Federal income taxes are allocated among the subsidiaries in
accordance with the federal taxable income or loss of each member of the
consolidated group. State income taxes are allocated by reference to each
company's contribution to the state income tax liability in each state in which
PPL Corporation and its subsidiaries do business.
86
THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
We are offering to issue our Senior Notes, 6.40% Exchange Series A due 2011
which have been registered under the Securities Act, which we refer to as the
"new notes," in exchange for our Senior Notes, 6.40% Series A due 2011, which
have not been so registered, which we refer to as the "old notes," as described
herein (the "exchange offer").
The old notes were sold to Morgan Stanley & Co. Incorporated, Barclays
Capital Inc., Banc of America Securities, LLC, Banc One Capital Markets, Inc.,
J.P. Morgan Securities Inc., Merrill Lynch, Pierce, Fenner & Incorporated,
Salomon Brothers Inc., Scotia Capital (USA) Inc., First Union Securities Inc.
and Westdeutsche Landesbank Gironzentrale, which we refer to as the initial
purchasers, on October 19, 2001 for resale to a limited number of institutional
investors in a private offering. In connection with the sale of the old notes,
we and the initial purchasers entered into a Registration Rights Agreement,
dated October 19, 2001, which requires, among other things, us
(a) to file with the SEC an exchange offer registration statement under
the Securities Act with respect to new notes identical in all material
respects to the old notes, to use reasonable best efforts to cause such
registration statement to be declared effective under the Securities Act and
to make an exchange offer for the old notes as discussed below, or
(b) to register the old notes on a shelf registration statement under the
Securities Act.
We are obligated, upon the effectiveness of the exchange offer registration
statement referred to in (a) above, to offer the holders of the old notes the
opportunity to exchange their old notes for a like principal amount of new
notes which will be issued without a restrictive legend and may be reoffered
and resold by the holder without restrictions or limitations under the
Securities Act. A copy of the Registration Rights Agreement has been filed as
an exhibit to the registration statement of which this prospectus is a part.
The exchange offer is being made pursuant to the Registration Rights Agreement
to satisfy our obligations under that agreement.
The old notes and Registration Rights Agreement provide, among other things,
that if the exchange offer has not been consummated within the required time
period, the interest rate on the old notes will be increased by up to a maximum
additional interest rate of 0.50% per annum until the exchange offer is
consummated.
The term "holder" with respect to the exchange offer means any person in
whose name old notes are registered on our books, any other person who has
obtained a properly completed assignment from the registered holder or any DTC
participant whose old notes are held of record by DTC. At the date of this
prospectus, the sole holder of old notes is DTC.
In participating in the exchange offer, a holder is deemed to represent to
us, among other things, that
. any new notes to be received by it will be acquired in the ordinary
course of its business,
. it has no arrangement or understanding with any person to participate in
the distribution of the old notes or the new notes within the meaning of
the Securities Act,
. it is not an "affiliate" of ours, as defined in Rule 405 under the
Securities Act, or if it is an affiliate, that it will comply with the
registration and prospectus delivery requirements of the Securities Act
to the extent applicable, and
. if such holder is not a broker-dealer, that it is not engaged in, and
does not intend to engage in, a distribution of such new notes.
Based on an interpretation by the staff of the SEC set forth in no-action
letters issued to third-parties, we believe that the new notes issued pursuant
to the exchange offer may be offered for resale and resold or otherwise
transferred by any holder of such new notes (other than any such holder which
is an "affiliate" of ours within the
87
meaning of Rule 405 under the Securities Act and except as otherwise discussed
below with respect to holders which are broker-dealers) without compliance with
the registration and prospectus delivery requirements of the Securities Act, so
long as such new notes are acquired in the ordinary course of such holder's
business and such holder has no arrangement or understanding with any person to
participate in the distribution (within the meaning of the Securities Act) of
such new notes. Any holder who tenders in the exchange offer for the purpose of
participating in a distribution of the new notes cannot rely on such
interpretation by the staff of the SEC and must comply with the registration
and prospectus delivery requirements of the Securities Act in connection with a
secondary resale transaction. Under no circumstances may this prospectus be
used for any offer to resell or any resale or other transfer in connection with
a distribution of the new notes. In the event that our belief is not correct,
holders of the new notes who transfer new notes in violation of the prospectus
delivery provisions of the Securities Act and without an exemption from
registration thereunder may incur liability thereunder. We do not assume or
indemnify holders against such liability.
Each broker-dealer that receives new notes for its own account in exchange
for old notes, where such old notes were acquired by such broker-dealer as a
result of market-making activities or other trading activities must, and must
agree to, deliver a prospectus in connection with any resale of such new notes.
This prospectus may be used for such purpose. Any such broker-dealer may be
deemed to be an "underwriter" within the meaning of the Securities Act. The
foregoing interpretation of the staff of the SEC does not apply to, and this
prospectus may not be used in connection with, the resale by any broker-dealer
of any new notes received in exchange for an unsold allotment of old notes
purchased directly from us. See "Plan of Distribution."
We have not entered into any arrangement or understanding with any person to
distribute the new notes to be received in the exchange offer.
The exchange offer is not being made to, nor will we accept tenders for
exchange from, holders of old notes in any jurisdiction in which the exchange
offer or the acceptance thereof would not be in compliance with the securities
or blue sky laws of such jurisdiction.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions set forth in this prospectus
and in the letter of transmittal, we will accept any and all old notes properly
tendered and not withdrawn prior to 5:00 p.m., New York City time, on the
expiration date. Holders may tender their old notes in whole or in part in
minimum denominations of $100,000 and integral multiples of $1,000 in excess
thereof. For each old note accepted for exchange, the holder of the old note
will receive a new note having a principal amount equal to that of the
surrendered old note.
The form and terms of the new notes will be the same as the form and terms
of the old notes, except that the registration rights and related additional
interest provisions and the transfer restrictions applicable to the old notes
are not applicable to the new notes. The new notes will evidence the same debt
as the old notes. The new notes will be issued under and entitled to the
benefits of the Indenture pursuant to which the old notes were issued. The new
notes will be registered under the Securities Act while the old notes were not.
No interest will be paid in connection with the exchange. The new notes will
bear interest from and including the last Interest Payment Date (as hereinafter
defined) on the old notes, or if one has not yet occurred, the issuance date of
the old notes. Accordingly, the holders of old notes that are accepted for
exchange will not receive accrued but unpaid interest on old notes at the time
of tender. Rather, that interest will be payable on the new notes delivered in
exchange for the old notes on the first Interest Payment Date after the
expiration date.
As of the date of this prospectus, $500,000,000 in aggregate principal
amount of the old notes is outstanding. This prospectus, together with the
letter of transmittal, is being sent to all registered holders of the old notes.
88
We will be deemed to have accepted validly tendered old notes when, as and
if we shall have given oral (promptly confirmed in writing) or written notice
thereof to the exchange agent. The exchange agent will act as agent for the
tendering holders for the purpose of receiving the new notes from us.
Old notes that are not tendered for exchange in the exchange offer will
remain outstanding and will be entitled to the rights and benefits such holders
have under the Indenture. If any tendered old notes are not accepted for
exchange because of an invalid tender, the occurrence of certain other events
set forth herein or otherwise, certificates for any such unaccepted old notes
will be returned, without expense, to the tendering holder thereof as promptly
as practicable after the expiration date.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS TO THE EXCHANGE OFFER
The term "expiration date," shall mean 5:00 p.m., New York City time on ,
2002, unless we, in our sole discretion, extend the exchange offer, in which
case the term "expiration date" shall mean the latest date and time to which
the exchange offer is extended.
In order to extend the exchange offer, we will notify the exchange agent of
any extension by oral (promptly confirmed in writing) or written notice and
will mail to the registered holders an announcement thereof, prior to 9:00
a.m., New York City time, on the next business day after the then expiration
date.
We reserve the right, in our sole discretion,
. to delay accepting any old notes, to extend the exchange offer or to
terminate the exchange offer if any of the conditions set forth below
under "--Conditions to the Exchange Offer" shall not have been satisfied
by giving oral (promptly confirmed in writing) or written notice of such
delay, extension or termination to the exchange agent or
. to amend the terms of the exchange offer in any manner.
Any such delay in acceptances, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice thereof to the
registered holders. If the exchange offer is amended in a manner that we
determine constitutes a material change, we will promptly disclose such
amendment by means of a prospectus supplement that will be distributed to the
registered holders of the old notes, and we will extend the exchange offer to
the extent required by law.
Without limiting the manner in which we may choose to make a public
announcement of any delay, extension, amendment or termination of the exchange
offer, we will have no obligation to publish, advertise, or otherwise
communicate any such public announcement, other than by making a timely release
to an appropriate news agency.
Upon satisfaction or waiver of all the conditions to the exchange offer, we
will accept, promptly after the expiration date, all old notes properly
tendered and will issue the new notes promptly after acceptance of the old
notes. See "--Conditions to the Exchange Offer." For purposes of the exchange
offer, we will be deemed to have accepted properly tendered old notes for
exchange when, as and if we shall have given oral (promptly confirmed in
writing) or written notice thereof to the exchange agent.
In all cases, issuance of the new notes for old notes that are accepted for
exchange pursuant to the exchange offer will be made only after timely receipt
by the exchange agent of a properly completed and duly executed letter of
transmittal (or facsimile thereof or an agent's message (as hereinafter
defined) in lieu thereof) and all other required documents; PROVIDED, HOWEVER,
that we reserve the absolute right to waive any defects or irregularities in
the tender or conditions of the exchange offer. If any tendered old notes are
not accepted for any reason set forth in the terms and conditions of the
exchange offer or if old notes are submitted for a greater principal amount
than the holder desires to exchange, then such unaccepted or non-exchanged old
notes evidencing the unaccepted or non-exchanged portion, as appropriate, will
be returned without expense to the tendering holder thereof as promptly as
practicable after the expiration or termination of the exchange offer.
89
CONDITIONS TO THE EXCHANGE OFFER
Notwithstanding any other term of the exchange offer, we will not be
required to exchange any new notes for any old notes and may terminate the
exchange offer before the acceptance of any old notes for exchange, if:
. any action or proceeding is instituted or threatened in any court or by
or before any governmental agency with respect to the exchange offer
which, in our reasonable judgment, might materially impair our ability
to proceed with the exchange offer; or
. any law, statute, rule or regulation is proposed, adopted or enacted, or
any existing law, statute, rule or regulation is interpreted by the
staff of the SEC, which, in our reasonable judgment, might materially
impair our ability to proceed with the exchange offer.
If we determine in our sole discretion that any of these conditions are not
satisfied, we may
. refuse to accept any old notes and return all tendered old notes to the
tendering holders,
. extend the exchange offer and retain all old notes tendered prior to the
expiration of the exchange offer, subject, however, to the rights of
holders who tendered such old notes to withdraw their tendered old
notes, or
. waive such unsatisfied conditions with respect to the exchange offer and
accept all properly tendered old notes which have not been withdrawn. If
such waiver constitutes a material change to the exchange offer, we will
promptly disclose such waiver by means of a prospectus supplement that
will be distributed to the registered holders, and we will extend the
exchange offer to the extent required by law.
PROCEDURES FOR TENDERING--REGISTERED HOLDERS AND DTC PARTICIPANTS
REGISTERED HOLDERS OF OLD NOTES, AS WELL AS BENEFICIAL OWNERS WHO ARE DIRECT
PARTICIPANTS IN DTC, WHO DESIRE TO PARTICIPATE IN THE EXCHANGE OFFER SHOULD
FOLLOW THE DIRECTIONS SET FORTH BELOW AND IN THE LETTER OF TRANSMITTAL.
ALL OTHER BENEFICIAL OWNERS SHOULD FOLLOW THE INSTRUCTIONS RECEIVED FROM
THEIR BROKER OR NOMINEE AND SHOULD CONTACT THEIR BROKER OR NOMINEE DIRECTLY.
THE INSTRUCTIONS SET FORTH BELOW AND IN THE LETTER OF TRANSMITTAL DO NOT APPLY
TO SUCH BENEFICIAL OWNERS.
REGISTERED HOLDERS
To tender in the exchange offer, a holder must complete, sign and date the
letter of transmittal, or facsimile thereof, have the signatures thereon
guaranteed if required by the letter of transmittal, and mail or otherwise
deliver such letter of transmittal or such facsimile to the exchange agent
prior to the expiration date. In addition, either
. certificates for such old notes must be received by the exchange agent
along with the letter of transmittal, or
. the holder must comply with the guaranteed delivery procedures described
below.
To be tendered effectively, the letter of transmittal and other required
documents must be received by the exchange agent at the address set forth below
under "--Exchange Agent" prior to the expiration date.
The tender by a holder which is not withdrawn prior to the expiration date
will constitute an agreement between such holder and us in accordance with the
terms and subject to the conditions set forth herein and in the letter of
transmittal.
THE METHOD OF DELIVERY OF OLD NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER
REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF THE
HOLDER, BUT THE DELIVERY WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED OR
CONFIRMED BY THE EXCHANGE AGENT. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED
THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES,
SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT
BEFORE THE EXPIRATION DATE. NO LETTER OF TRANSMITTAL OR OLD NOTES SHOULD BE
SENT TO US. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS, COMMERCIAL
BANKS, TRUST COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR SUCH
HOLDERS.
90
Signatures on a letter of transmittal or a notice of withdrawal, as the case
may be, must be guaranteed by an "eligible institution" (as defined below)
unless the old notes tendered pursuant thereto is tendered
. by a registered holder who has not completed the box entitled "Special
Payment Instructions" or "Special Delivery Instructions" on the letter
of transmittal or
. for the account of an eligible institution (as defined below).
In the event that signatures on a letter of transmittal or a notice of
withdrawal, as the case may be, are required to be guaranteed, such guarantor
must be a member firm of a registered national securities exchange or of the
National Association of Securities Dealers, Inc., a commercial bank or trust
company having an office or correspondent in the United States or an "eligible
guarantor institution" within the meaning of Rule 17Ad-15 under the Exchange
Act (an "eligible institution").
If the letter of transmittal is signed by a person other than the registered
holder of any old notes listed therein, such old notes must be endorsed or
accompanied by a properly completed bond power signed by such registered holder
as such registered holder's name appears on such old notes.
If the letter of transmittal or any old notes or bond or stock powers are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, such persons should so indicate when signing, and unless waived by
us, evidence satisfactory to us of their authority to so act must be submitted
with the letter of transmittal.
DTC PARTICIPANTS
Any financial institution that is a participant in DTC's systems may make
book-entry delivery of old notes by causing DTC to transfer such old notes into
the exchange agent's account at DTC in accordance with DTC's procedures for
transfer. Such delivery must be accompanied by either
. the letter of transmittal or facsimile thereof, with any required
signature guarantees or
. an agent's message (as hereinafter defined),
and any other required documents, and must, in any case, be transmitted to and
received by the exchange agent at the address set forth below under "--Exchange
Agent" prior to the expiration date or the guaranteed delivery procedures
described above must be complied with. The exchange agent will make a request
to establish an account with respect to the old notes at DTC for purposes of
the exchange offer within two business days after the date of this prospectus.
The term "agent's message" means a message, electronically transmitted by
DTC to and received by the exchange agent, and forming a part of the Book-Entry
Confirmation, which states that DTC has received an express acknowledgement
from a holder of old notes stating that such holder has received and agrees to
be bound by, and makes each of the representations and warranties contained in,
the letter of transmittal and, further, that such holder agrees that we may
enforce the letter of transmittal against such holder.
GUARANTEED DELIVERY PROCEDURES
Holders who wish to tender their old notes and
. whose old notes are not immediately available,
. who cannot deliver their old notes, the letter of transmittal or any
other required documents to the exchange agent prior to the expiration
date, or
. who cannot complete the procedures for book-entry tender on a timely
basis
91
may effect a tender if:
(1) the tender is made through an eligible institution;
(2) prior to the expiration date, the exchange agent receives from
such eligible institution a properly completed and duly executed Notice
of Guaranteed Delivery (by facsimile transmission, mail or hand
delivery), setting forth the name and address of the holder, the
certificate number(s) of such old notes (unless tender is to be made by
book-entry transfer) and the principal amount of old notes tendered,
stating that the tender is being made thereby and guaranteeing that,
within five New York Stock Exchange trading days after the date of
delivery of the Notice of Guaranteed Delivery, the certificates for all
physically tendered old notes, in proper form for transfer, or
Book-Entry Confirmation (as defined in the letter of transmittal), as
the case may be, together with a properly completed and duly executed
letter of transmittal (or facsimile thereof or agent's message in lieu
thereof), with any required signature guarantees and all other documents
required by the letter of transmittal, will be deposited by the eligible
institution with the exchange agent; and
(3) the certificates and/or other documents referred to in clause (2)
above must be received by the exchange agent within the time specified
above.
Upon request to the exchange agent a Notice of Guaranteed Delivery will be
sent to holders who wish to tender their old notes according to the guaranteed
delivery procedures set forth above.
MISCELLANEOUS
All questions as to the validity, form, eligibility (including time of
receipt), acceptance of tendered old notes and withdrawal of tendered old notes
will be determined by us in our sole discretion, which determination will be
final and binding. We reserve the absolute right to reject any and all old
notes not properly tendered or any old notes our acceptance of which would, in
the opinion of our counsel, be unlawful. We also reserve the right to waive any
defects, irregularities or conditions of tender as to particular old notes. Our
interpretation of the terms and conditions of the exchange offer (including the
instructions in the letter of transmittal) will be final and binding on all
parties. Unless waived, any defects or irregularities in connection with
tenders of old notes must be cured within such time as we shall determine.
Although we intend to notify holders of defects or irregularities with respect
to tenders of old notes, none of PPL Energy Supply, the exchange agent, nor any
other person shall incur any liability for failure to give such notification.
Tenders of old notes will not be deemed to have been made until such defects or
irregularities have been cured or waived. Any old notes received by the
exchange agent that are not properly tendered and as to which the defects or
irregularities have not been cured or waived will be returned by the exchange
agent to the tendering holders, unless otherwise provided in the letter of
transmittal, as soon as practicable following the expiration date.
In all cases, issuance of new notes pursuant to the exchange offer will be
made only after timely receipt by the exchange agent of certificates for the
old notes tendered for exchange or a timely Book-Entry Confirmation of such old
notes into the exchange agent's account at DTC, a properly completed and duly
executed letter of transmittal (or facsimile thereof or agent's message in lieu
thereof) and all other required documents. If any tendered old notes are not
accepted for any reason set forth in the terms and conditions of the exchange
offer or if old notes are submitted for a greater principal amount than the
holder desires to exchange, such unaccepted or non-exchanged old notes will be
returned without expense to the tendering holder thereof (or, in the case of
old notes tendered by book-entry transfer into the exchange agent's account at
DTC pursuant to the book-entry transfer procedures described below, such
unaccepted or non-exchanged old notes will be credited to an account maintained
with DTC) as promptly as practicable after the expiration or termination of the
exchange offer.
Each broker-dealer that receives new notes for its own account in exchange
for old notes, where such old notes were acquired by such broker-dealer as a
result of market-making activities or other trading activities, must
acknowledge that it will deliver a prospectus in connection with any resale of
such new notes. See "Plan of Distribution."
92
We reserve the right in our sole discretion to purchase or make offers for
any old notes that remain outstanding subsequent to the expiration date or, as
set forth above under "--Conditions to the Exchange Offer," to terminate the
exchange offer and, to the extent permitted by applicable law, purchase old
notes in the open market, in privately negotiated transactions or otherwise.
The terms of any such purchases or offers could differ from the terms of the
exchange offer.
WITHDRAWAL OF TENDERS OF OLD NOTES
Except as otherwise provided herein, tenders of old notes may be withdrawn
at any time prior to 5:00 p.m., New York City time, on the expiration date.
To withdraw a tender of old notes in the exchange offer, a written or
facsimile transmission notice of withdrawal must be received by the exchange
agent at its address set forth herein prior to 5:00 p.m., New York City time,
on the expiration date. Any such notice of withdrawal must
. specify the name of the person having deposited the old notes to be
withdrawn, which we refer to as the "depositor,"
. identify the old notes to be withdrawn (including the certificate number
(unless tendered by book-entry transfer)),
. be signed by the holder in the same manner as the original signature on
the letter of transmittal by which such old notes were tendered
(including any required signature guarantees) or be accompanied by
documents of transfer sufficient to have the Trustee with respect to the
old notes register the transfer of such old notes in the name of the
person withdrawing the tender, and
. specify the name in which any such old notes are to be registered, if
different from that of the depositor. If old notes have been tendered
pursuant to book-entry transfer, any notice of withdrawal must specify
the name and number of the account at DTC to be credited with the
withdrawn old notes, in which case a notice of withdrawal will be
effective if delivered to the exchange agent by any method of delivery
described in this paragraph.
All questions as to the validity, form and eligibility (including time of
receipt) of such notices will be determined by us, which determination shall be
final and binding on all parties. Any old notes so withdrawn will be deemed not
to have been validly tendered for purposes of the exchange offer and will be
returned to the holder thereof without cost to such holder as soon as
practicable after withdrawal; and no new notes will be issued with respect
thereto unless the old notes so withdrawn are validly retendered. Properly
withdrawn old notes may be retendered by following one of the procedures
described above under "-- Procedures for Tendering" at any time prior to the
expiration date.
EXCHANGE AGENT
JPMorgan Chase Bank has been appointed as exchange agent of the exchange
offer. Requests for additional copies of this prospectus or of the letter of
transmittal and requests for Notice of Guaranteed Delivery with respect to the
exchange of the old notes should be directed to the exchange agent addressed as
follows:
JP Morgan Chase Bank
55 Water Street, Room 234
New York, New York 10041
Attention: Victor Matis
BY TELEPHONE: (212) 638-0459
BY FACSIMILE: (212) 638-7380
93
FEES AND EXPENSES
We will pay the expenses of soliciting tenders. The principal solicitation
is being made by mail; however, additional solicitation may be made by
telecopier, telephone or in person by officers and regular employees of PPL
Energy Supply and our affiliates.
We have not retained any dealer-manager in connection with the exchange
offer and will not make any payments to brokers, dealers or others soliciting
acceptances of the exchange offer. We, however, will pay the exchange agent
reasonable and customary fees for its services and will reimburse it for its
reasonable out-of-pocket expenses in connection therewith. We will also pay
brokerage houses and other custodians, nominees and fiduciaries the reasonable
out-of-pocket expenses incurred by them in forwarding copies of this prospectus
and related documents to the beneficial owners of the old notes and in handling
or forwarding tenders for exchange for their customers.
We will pay all transfer taxes, if any, applicable to the exchange of the
old notes pursuant to the exchange offer. If, however, certificates
representing new notes for principal amounts not tendered or accepted for
exchange are to be delivered to, or are to be issued in the name of, any person
other than the registered holder of old notes tendered, or if tendered old
notes are registered in the name of any person other than the person signing
the letter of transmittal, or if a transfer tax is imposed for any reason other
than the exchange of the old notes pursuant to the exchange offer, then the
amount of any such transfer taxes (whether imposed on the registered holder or
any other persons) will be payable by the tendering holder. If satisfactory
evidence of payment of such taxes or exemption therefrom is not submitted with
the letter of transmittal, the amount of such transfer taxes will be billed
directly to such tendering holder.
ACCOUNTING TREATMENT
We will record the new notes at the same carrying value as the old notes for
which they are exchanged, which is the aggregate principal amount of the old
notes, as reflected in our accounting records on the date of exchange.
Accordingly, no gain or loss for accounting purposes will be recognized in
connection with the exchange offer. The cost of the exchange offer will be
amortized over the term of the new notes.
APPRAISAL OR DISSENTERS' RIGHTS
Holders of the old notes will not have appraisal or dissenters' rights in
connection with the exchange offer.
94
DESCRIPTION OF THE NEW NOTES
The following description sets forth certain terms and provisions of the new
notes. We issued the old notes, and will issue the new notes under an
Indenture, dated as of October 1, 2001 (as such indenture has been and may be
supplemented, the "Indenture"), between us and The Chase Manhattan Bank, as
trustee, which we refer to as the Trustee.
The provisions of the Indenture, as supplemented by Supplemental Indenture
No. 1 thereto, are incorporated herein by this reference and the Indenture as
so supplemented is available upon request to the Trustee. The Indenture and its
associated documents contain the full legal text of the matters described in
this section. Because this section is a summary, it does not describe every
aspect of the new notes or the Indenture. This summary is subject to and
qualified in its entirety by reference to all of the provisions of the new
notes and the Indenture, including definitions of certain terms used in the
Indenture. We also include references in parentheses to certain sections of the
Indenture. Whenever we refer to particular sections or defined terms of the
Indenture in this prospectus, such sections or defined terms are incorporated
by reference herein. The old notes and the new notes are sometimes collectively
called the "senior notes."
GENERAL
Our Senior Notes, 6.40% Series A due 2011, or the "old notes", were issued
in the principal amount of $500,000,000. We may, without the consent of the
holders, increase such principal amount in the future on the same terms and
conditions and with the same CUSIP number(s) as the old notes.
We will offer the new notes as a series of our Senior Notes, 6.40% Exchange
Series A due 2011, in the principal amount of $500,000,000. The new notes will
be identical in all material respects to the old notes, except that the
registration rights and related additional interest provisions and transfer
restrictions applicable to the old notes are not applicable to the new notes.
The new notes will not be of the same series as the old notes, but both the old
notes and the new notes will be considered as a single class for purposes of
any acts of Holders (such as voting and consents) under the Indenture. To the
extent any old notes are not exchanged for new notes, those old notes will
remain outstanding under the Indenture and will rank pari passu with the new
notes.
The new notes will mature on November 1, 2011 and will bear interest from
the last interest payment date on the old notes, or if no interest payment date
has occurred, the date of original issuance of the old notes, at the rate of
6.40% per annum. Interest will be payable on May 1 and November 1 of each year
(each, an Interest Payment Date) commencing May 1, 2002, until maturity.
Subject to certain exceptions, the Indenture provides for the payment of
interest on an Interest Payment Date only to persons in whose names the new
notes are registered at the close of business on the Regular Record Date, which
will be the April 15 or October 15 (whether or not a Business Day), as the case
may be, immediately preceding the applicable Interest Payment Date. Interest
will be calculated on the basis of a 360-day year of twelve 30-day months.
The Indenture does not limit the amount of debt securities that may be
issued thereunder, and PPL Energy Supply may, from time to time, without the
consent of the Holders (as defined below) of the old notes or the new notes,
provide for the issuance of other debt securities under the Indenture in
addition to the old notes and the new notes. We refer to the old notes, the new
notes and all other debt securities issued under the Indenture as the Indenture
Securities.
The new notes will be issued in fully registered form, without interest
coupons, and in denominations of $100,000 or any integral multiples of $1,000
in excess of $100,000. (See Section 302.). The new notes will initially be
issued in book-entry form, and we refer to new notes so represented as
Book-Entry Notes. Each Book-Entry Note will be represented by one or more fully
registered global notes, or Global Notes, deposited with or on behalf of DTC,
as Depositary, and registered in the name of the Depositary or the Depositary's
nominee. Except under the limited circumstances described in this prospectus,
the new notes will not be exchangeable for certificated notes in definitive
form.
95
PAYMENT OF PRINCIPAL AND ANY PREMIUM AND INTEREST
We will ordinarily pay interest on each new note on each Interest Payment
Date by check mailed to the person in whose name such new note is registered
(the registered holder of any Indenture Security being called a "Holder" in
this prospectus) as of the close of business on the Regular Record Date
relating to such Interest Payment Date, EXCEPT that:
. interest payable at maturity (whether at stated maturity, upon
redemption or otherwise, referred to as Maturity) will be paid to the
person to whom principal is paid;
. if and to the extent PPL Energy Supply defaults in the payment of the
interest due on any new note on any Interest Payment Date, such
defaulted interest will be paid as described below;
. if the registered Holder is the Depositary or its nominee, such payment
may be made in accordance with any other arrangements then in effect
among PPL Energy Supply, the Trustee or other Paying Agent and the
Depositary; and
. a registered Holder of $10,000,000 or more in aggregate principal amount
of new notes will be entitled to receive interest payments, if any, on
any Interest Payment Date other than at Maturity by wire transfer of
immediately available funds, if appropriate wire transfer instructions
have been received in writing by the Trustee not less than 15 days prior
to such Interest Payment Date. Any such wire transfer instructions
received by the Trustee will remain in effect until revoked by such
Holder.
If we default in paying interest on a new note, we will pay defaulted
interest in either of the two following ways:
. We will first propose to the Trustee a payment date for such defaulted
interest. Next, the Trustee will choose a Special Record Date for
determining which Holders are entitled to the payment. The Special
Record Date will be between 10 and 15 days before the payment date we
propose. Finally, we will pay such defaulted interest on the payment
date to the Holder of the new note as of the close of business on the
Special Record Date.
. Alternatively, we can propose to the Trustee any other lawful manner of
payment that is consistent with the requirements of any securities
exchange on which such new notes are listed for trading. If the Trustee
thinks the proposal is practicable, payment will be made as proposed.
(See Section 307.)
We will pay principal of and any interest and premium on the new notes at
Maturity upon presentation of the new notes at the office of The Chase
Manhattan Bank in New York, New York, as our Paying Agent. In our discretion,
we may change the place of payment on the new notes, and may remove any Paying
Agent and may appoint one or more additional Paying Agents (including PPL
Energy Supply or any of our affiliates). (See Section 602.)
If any Interest Payment Date, Redemption Date or the Maturity of a new note
falls on a day that is not a Business Day, the required payment of principal,
premium, if any, and/or interest will be made on the next succeeding Business
Day as if made on the date such payment was due, and no interest will accrue on
such payment for the period from and after such Interest Payment Date,
Redemption Date or the Maturity, as the case may be, to the date of such
payment on the next succeeding Business Day. "Business Day" means any day,
other than a Saturday or Sunday, that is not a day on which banking
institutions or trust companies are generally authorized or required by law,
regulation or executive order to close in The City of New York or other city in
which any Paying Agent for the new notes is located (See Section 113.)
So long as the Depositary is the registered owner of any Global Note, the
Depositary, or its nominee, as the case may be, will be considered the sole
Holder of the Book-Entry Notes represented by such Global Note for all purposes
under the Indenture, including payments. Accordingly, so long as the Depositary
is the registered owner
96
of any Global Note, payments of principal and any premium and interest on
Book-Entry Notes represented by such Global Note will be made to the Depositary
as described below under "--Book-Entry Notes."
TRANSFERS; EXCHANGES
A beneficial interest in a Global Note will be shown on, and transfers or
exchanges thereof will be effected only through, records maintained by the
Depositary and its participants, as described below under "--Book-Entry Notes."
You may purchase Book-Entry Notes only in a minimum denomination of $100,000
and in integral multiples of $1,000. Except in limited circumstances described
below, Book-Entry Notes will not be exchangeable for new notes in fully
registered certificated form, which we refer to as Certificated Notes.
If Certificated Notes are issued, you may exchange or transfer Certificated
Notes at the office of the Trustee. Certificated Notes may be divided into
notes of smaller denominations (of at least $100,000) or combined into notes of
larger denominations, as long as the total principal amount is not changed. The
Trustee acts as our agent for registering Certificated Notes in the names of
holders and transferring debt securities. We may appoint another agent or act
as our own agent for this purpose. The entity performing the role of
maintaining the list of registered holders is called the Security Registrar. It
will also perform transfers.
In our discretion, we may change the place for registration of transfer of
the new notes and may remove and/or appoint one or more additional Security
Registrars (including PPL Energy Supply or any of our affiliates). (See
Sections 305 and 602.)
There will be no service charge for any transfer or exchange of the new
notes, but you may be required to pay a sum sufficient to cover any tax or
other governmental charge payable in connection therewith. We may block the
transfer or exchange of (1) new notes during a period of 15 days prior to
giving any notice of redemption or (2) any new note selected for redemption in
whole or in part, except the unredeemed portion of any new note being redeemed
in part. (See Section 305.)
REDEMPTION
The new notes will be redeemable at the election of PPL Energy Supply, in
whole at any time or in part from time to time, at a redemption price equal to
the greater of:
(a) 100% of the principal amount of the new notes to be so redeemed; or
(b) as determined by an Independent Investment Banker, the sum of the
present values of the remaining scheduled payments of principal and interest
on the new notes to be so redeemed (not including any portion of such
payments of interest accrued to the date of redemption) discounted to the
redemption date on a semiannual basis (assuming a 360-day year consisting of
twelve 30-day months) at the Adjusted Treasury Rate, plus 25 basis points,
plus, in either of the above cases, accrued and unpaid interest to the date of
redemption.
"Adjusted Treasury Rate" means, with respect to any redemption date:
(a) the yield, under the heading which represents the average for the
immediately preceding week, appearing in the most recently published
statistical release designated "H.15(519)" or any successor publication
which is published weekly by the Board of Governors of the Federal Reserve
System and which establishes yields on actively traded United States
Treasury securities adjusted to constant maturity under the caption
"Treasury Constant Maturities," for the maturity corresponding to the
Comparable Treasury Issue (if no maturity is within three months before or
after the Remaining Life, yields for the two published maturities most
closely corresponding to the Comparable Treasury Issue will be determined
and the Adjusted Treasury Rate will be interpolated or extrapolated from
such yields on a straight line basis, rounding to the nearest month); or
97
(b) if such release (or any successor release) is not published during
the week preceding the calculation date or does not contain such yields, the
rate per annum equal to the semi-annual equivalent yield to maturity of the
Comparable Treasury Issue, calculated using a price for the Comparable
Treasury Issue (expressed as a percentage of its principal amount) equal to
the Comparable Treasury Price for such redemption date.
The Adjusted Treasury Rate will be calculated on the third Business Day
preceding the redemption date.
"Comparable Treasury Issue" means the United States Treasury security
selected by an Independent Investment Banker as having a maturity comparable to
the remaining term to the stated maturity date of the new notes to be redeemed
that would be utilized, at the time of selection and in accordance with
customary financial practice, in pricing new issues of corporate debt
securities of comparable maturity to the remaining term of the new notes (the
"Remaining Life").
"Comparable Treasury Price" means (1) the average of five Reference Treasury
Dealer Quotations for such redemption date, after excluding the highest and
lowest Reference Treasury Dealer Quotations, or (2) if the Independent
Investment Banker obtains fewer than five such Reference Treasury Dealer
Quotations, the average of all such quotations.
"Independent Investment Banker" means one of the Reference Treasury Dealers
appointed by PPL Energy Supply.
"Reference Treasury Dealer" means:
(a) Morgan Stanley & Co. Incorporated and Barclays Capital Inc., and
their respective successors; PROVIDED, HOWEVER, that if either of the
foregoing shall cease to be a primary U.S. Government securities dealer in
New York City (a "Primary Treasury Dealer"), PPL Energy Supply will
substitute another Primary Treasury Dealer; and
(b) any three other Primary Treasury Dealers selected by PPL Energy
Supply.
"Reference Treasury Dealer Quotations" means, with respect to each Reference
Treasury Dealer and any redemption date, the average, as determined by the
Independent Investment Banker, of the bid and asked prices for the Comparable
Treasury Issue (expressed in each case as a percentage of its principal amount)
quoted in writing to the Independent Investment Banker at 5:00 p.m., New York
City time, on the third Business Day preceding such redemption date.
The new notes will not be subject to a sinking fund or other mandatory
redemption and will not be repayable at the option of the Holder prior to the
Stated Maturity Date.
New notes will be redeemable upon notice by mail between 30 and 60 days
prior to the redemption date. If less than all of the new notes thereof are to
be redeemed, the Trustee will select the new notes to be redeemed. In the
absence of any provision for selection, the Trustee will choose a method of
random selection as it deems fair and appropriate. (See Sections 403 and 404.)
New notes will cease to bear interest on the redemption date. PPL Energy
Supply will pay the redemption price and any accrued interest once you
surrender the new note for redemption. (See Section 405.) If only part of a new
note is redeemed, the Trustee will deliver to you an additional new note of the
same series for the remaining portion without charge. (See Section 406.)
We may make any redemption at the option of PPL Energy Supply conditional
upon the receipt by the Paying Agent, on or prior to the date fixed for
redemption, of money sufficient to pay the redemption price. If the Paying
Agent has not received such money by the date fixed for redemption, we will not
be required to redeem such new notes. (See Section 404.)
98
EVENTS OF DEFAULT
An "Event of Default" occurs with respect to the new notes if
. we do not pay any interest on any new notes within 30 days of the due
date;
. we do not pay principal or premium on any new notes on its due date;
. we remain in breach of any of our covenants (excluding covenants solely
applicable to a specific series) or warranties in the Indenture for 60
days after we receive a written notice of default stating we are in
breach and requiring remedy of the breach; the notice must be sent by
either the Trustee or Holders of 25% of the principal amount of
Indenture Securities of the affected series; the Trustee or such Holders
can agree to extend the 60-day period and such an agreement to extend
will be automatically deemed to occur if we are diligently pursuing
action to correct the default;
. a matured event of default, as defined in any of our instruments under
which there may be issued or evidenced any Debt of our company that has
resulted in the acceleration of such Debt, in excess of $25 million or
any default in payment of Debt in excess of $25 million at final
maturity (and after the expiration of any applicable grace or cure
periods); provided that the waiver or cure of any such default under any
such instrument shall constitute a waiver and cure of the corresponding
Event of Default under the Indenture and the rescission and annulment of
the consequences thereof shall constitute a rescission and annulment of
the corresponding consequences under the Indenture; or
. we file for bankruptcy or certain other similar events in bankruptcy,
insolvency, receivership or reorganization occur.
(See Section 801; Supplemental Indenture No. 1, Article One, Section 8.)
No Event of Default with respect to the new notes necessarily constitutes an
Event of Default with respect to the Indenture Securities of any other series
issued under the Indenture.
REMEDIES
ACCELERATION
ANY ONE SERIES. If an Event of Default occurs and is continuing with respect
to any one series of Indenture Securities, then either the Trustee or the
Holders of 25% in principal amount of the outstanding Indenture Securities of
such series may declare the principal amount of all of the Indenture Securities
of such series to be due and payable immediately.
MORE THAN ONE SERIES. If an Event of Default occurs and is continuing with
respect to more than one series of Indenture Securities, then either the
Trustee or the Holders of 25% in aggregate principal amount of the outstanding
Indenture Securities of all such series, considered as one class, may make such
declaration of acceleration. Thus, if there is more than one series affected,
the action by 25% in principal amount of the Indenture Securities of any
particular series will not, in itself, be sufficient to make a declaration of
acceleration.
(See Section 802.)
RESCISSION OF ACCELERATION
After the declaration of acceleration has been made and before the Trustee
has obtained a judgment or decree for payment of the money due, such
declaration and its consequences will be rescinded and annulled, if
(1)we pay or deposit with the Trustee a sum sufficient to pay
. all overdue interest;
. the principal of and any premium which have become due otherwise than
by such declaration of acceleration and interest thereon;
99
. interest on overdue interest to the extent lawful; and
. all amounts due to the Trustee under the Indenture; and
(2)all Events of Default, other than the nonpayment of the principal which
has become due solely by such declaration of acceleration, have been
cured or waived as provided in the Indenture.
(See Section 802.) For more information as to waiver of defaults, see "--Waiver
of Default and of Compliance" below.
CONTROL BY HOLDERS; LIMITATIONS
Subject to the Indenture, if an Event of Default with respect to the
Indenture Securities of any one series occurs and is continuing, the Holders of
a majority in principal amount of the outstanding Indenture Securities of that
series will have the right to
. direct the time, method and place of conducting any proceeding for any
remedy available to the Trustee, or
. exercise any trust or power conferred on the Trustee with respect to the
Indenture Securities of such series.
If an Event of Default is continuing with respect to more than one series of
Indenture Securities, the Holders of a majority in aggregate principal amount
of the outstanding Indenture Securities of all such series, considered as one
class, will have the right to make such direction, and not the Holders of the
Indenture Securities of any one of such series.
These rights of Holders to make direction are subject to the following
limitations:
. the Holders' directions may not conflict with any law or the Indenture;
and
. the Holders' directions may not involve the Trustee in personal
liability where the Trustee believes indemnity is not adequate.
The Trustee may also take any other action it deems proper which is
consistent with the Holders' direction. (See Sections 812 and 903.)
The Indenture provides that no Holder of any Indenture Security will have
any right to institute any proceeding, judicial or otherwise, with respect to
the Indenture for the appointment of a receiver or for any other remedy
thereunder unless
. that Holder has previously given the Trustee written notice of a
continuing Event of Default;
. the Holders of 25% in aggregate principal amount of the outstanding
Indenture Securities of all affected series, considered as one class,
have made written request to the Trustee to institute proceedings in
respect of that Event of Default and have offered the Trustee reasonable
indemnity against costs and liabilities incurred in complying with such
request; and
. for 60 days after receipt of such notice, the Trustee has failed to
institute any such proceeding and no direction inconsistent with such
request has been given to the Trustee during such 60-day period by the
Holders of a majority in aggregate principal amount of outstanding
Indenture Securities of all affected series, considered as one class.
Furthermore, no Holder will be entitled to institute any such action if and to
the extent that such action would disturb or prejudice the rights of other
Holders. (See Sections 807 and 903.)
However, each Holder has an absolute and unconditional right to receive
payment when due and to bring a suit to enforce that right. (See Sections 807
and 808.)
100
NOTICE OF DEFAULT
The Trustee is required to give the Holders of the Indenture Securities
notice of any default under the Indenture to the extent required by the Trust
Indenture Act, unless such default has been cured or waived; except that in the
case of an Event of Default of the character specified above in the third
bullet point under "Events of Default," no such notice shall be given to such
Holders until at least 45 days after the occurrence thereof. (See Section 902.)
The Trust Indenture Act currently permits the Trustee to withhold notices of
default (except for certain payment defaults) if the Trustee in good faith
determines the withholding of such notice to be in the interests of the Holders.
We will furnish the Trustee with an annual statement as to its compliance
with the conditions and covenants in the Indenture. (See Section 605.)
WAIVER OF DEFAULT AND OF COMPLIANCE
The Holders of a majority in aggregate principal amount of the outstanding
Indenture Securities of any series may waive, on behalf of the Holders of all
Indenture Securities of such series, any past default under the Indenture,
except a default in the payment of principal, premium or interest, or with
respect to compliance with certain provisions of the Indenture that cannot be
amended without the consent of the Holder of each outstanding Indenture
Security. (See Section 813.)
Compliance with certain covenants in the Indenture or otherwise provided
with respect to Indenture Securities may be waived by the Holders of a majority
in aggregate principal amount of the affected Indenture Securities, considered
as one class. (See Section 606.)
CERTAIN COVENANTS
LIMITATION ON ASSET SALES. We have agreed in the Indenture that, so long as
any of the new notes remain outstanding, except for the sale of assets required
to be sold to conform with governmental requirements and except for a sale of
our assets as or substantially as an entirety as contemplated under
"Consolidation, Merger and Conveyance of Assets as an Entirety," we will not
and will not permit any of our subsidiaries to, consummate any Asset Sale, if
the aggregate net book value of all such Asset Sales consummated during the
four calendar quarters immediately preceding any date of determination would
exceed 15% of our consolidated total assets as of the beginning of our most
recently ended full fiscal quarter; except that any such Asset Sale will be
disregarded for purposes of the 15% limitation specified above:
. if any such Asset Sale is in the ordinary course of business;
. if the assets subject to any such Asset Sale are worn out or are no
longer useful or necessary in connection with the operation of our
businesses;
. if the assets subject to any such Asset Sale are being transferred to
one of our wholly-owned subsidiaries;
. to the extent the assets subject to any such Asset Sale involve
transfers of assets of or equity interests in connection with (a) the
formation of any joint venture between us or any of our subsidiaries,
and any other entity, or (b) any project development and acquisition
activities;
. if the proceeds from any such Asset Sale (a) are, within 12 months of
such Asset Sale, invested or reinvested by us or any of our subsidiaries
in a Permitted Business, (b) are used by us or one of our subsidiaries
to repay debt of the company or such subsidiary, or (c) are retained by
us or our subsidiaries; or
. if, prior to any such Asset Sale, Moody's and S&P confirm the then
current senior unsecured long-term debt rating on the new notes after
giving effect to any such Asset Sale.
"ASSET SALE" means any sale of any assets, including by way of the sale by
us or any of our subsidiaries of equity interests in such subsidiaries.
101
"MOODY'S" means Moody's Investors Service, Inc. and its successors and
assigns, or absent a successor, or if such entity ceases to rate the new notes,
such other nationally recognized statistical rating organization as we may
designate.
"PERMITTED BUSINESS" means a business that is the same or similar to the
business of PPL Energy Supply or any of our subsidiaries as of the date hereof,
or any business reasonably related thereto.
"S&P" means Standard & Poor's Ratings Services, a division of The McGraw
Hill Companies, Inc. and its successors and assigns, or absent a successor, or
if such entity ceases to rate the new notes, such other nationally recognized
statistical rating organization as we may designate.
(See Supplemental Indenture No.1, Article One, Sections 6 and 10.)
RESTRICTIONS ON SECURED DEBT. We have agreed in the Indenture that, so long
as any of the new notes remain outstanding, PPL Energy Supply will not create,
incur or assume any Lien to secure Debt (in each case, as defined below) other
than Permitted Liens (as defined below) upon any of its property, without the
consent of the Holders of a majority in principal amount of the outstanding new
notes. This covenant will not, however, prohibit the creation, issuance,
incurrence or assumption of any Lien if either:
. we make effective provision whereby all of the new notes then
outstanding will be secured equally and ratably with all other Debt then
outstanding under such Lien; or
. we deliver to the Trustee bonds, notes or other evidences of
indebtedness secured by the Lien which secures such Debt in an aggregate
principal amount equal to the aggregate principal amount of the new
notes then outstanding and meeting certain other requirements set forth
in the Indenture.
This covenant applies to property held directly by PPL Energy Supply and
will not restrict the ability of its subsidiaries and affiliates to create,
incur or assume any Lien upon their assets, either in connection with project
financings or otherwise.
As used herein:
"DEBT," with respect to any entity, means:
. indebtedness of the entity for borrowed money evidenced by a bond,
debenture, note or other similar instrument or agreement by which the
entity is obligated to repay such borrowed money; and
. any guaranty by the entity of any such indebtedness of another entity.
"DEBT" does not include, among other things:
. indebtedness of the entity under any installment sale or conditional
sale agreement or any other agreement relating to indebtedness for the
deferred purchase price of property or services;
. trade obligations (including obligations under agreements relating to
the purchase and sale of any commodity, including power purchase or sale
agreements and any commodity hedges or derivatives regardless of whether
any such transaction is a "financial" or physical transaction) or other
obligations of the entity in the ordinary course of business;
. obligations of the entity under any lease agreement (including any lease
intended as security), whether or not such obligations are required to
be capitalized on the balance sheet of the entity under generally
accepted accounting principles, or
. liabilities secured by any Lien on any property owned by the entity if
and to the extent the entity has not assumed or otherwise become liable
for the payment thereof.
"LIEN" means any lien, mortgage, deed of trust, pledge or security interest,
in each case, intended to secure the repayment of Debt, except for any
Permitted Lien.
102
"MATERIAL SUBSIDIARY" means PPL Global, PPL EnergyPlus or PPL Generation.
"PERMITTED LIENS" means any
. Liens existing at the original issue date of the old notes;
. vendors' Liens, purchase money Liens and other Liens on property at the
time of its acquisition by us and Liens to secure or provide for the
construction or improvement of property provided that no such Lien shall
extend to or cover any of our other property;
. Liens on cash, securities (other than limited liability company
interests issued by any Material Subsidiary), deposit accounts and
interests in general or limited partnerships;
. Liens on the equity interest of any subsidiary of PPL Energy Supply that
is not a Material Subsidiary;
. Liens on property or shares of capital stock, or arising out of any
Debt, of any entity existing at the time the entity is merged into or
consolidated with PPL Energy Supply;
. Liens in connection with the issuance of tax-exempt industrial
development or pollution control bonds or other similar bonds issued
pursuant to Section 103(b) of the Internal Revenue Code of 1986, as
amended, to finance all or any part of the purchase price of or the cost
of constructing, equipping or improving property, provided that such
Liens are limited to the property acquired or constructed or improved
and to substantially unimproved real property on which such construction
or improvement is located; provided further, that PPL Energy Supply may
further secure all or any part of such purchase price or the cost of
construction or improvement by an interest on additional property of PPL
Energy Supply only to the extent necessary for the construction,
maintenance and operation of, and access to, such property so acquired
or constructed or such improvement;
. Liens on contracts, leases, and other agreements; Liens on contract
rights, bills, notes and other instruments; Liens on revenues, accounts,
accounts receivable and unbilled revenues, claims, credits, demands and
judgments; Liens on governmental and other licenses, permits,
franchises, consents and allowances; Liens on certain intellectual
property rights and other general intangibles;
. Liens securing Debt which matures less than one year from the date of
issuance or incurrence thereof and is not extendible at the option of
the issuer, and any refundings, refinancings and/or replacements of any
such Debt by or with similar secured Debt;
. Liens on vehicles, movable equipment and aircraft and parts, accessories
and supplies used in connection therewith, and Liens on furniture,
computers, data processing, telecommunications and other equipment and
facilities used primarily for administrative or clerical purposes;
. Liens on property which is the subject of a lease agreement designating
PPL Energy Supply as lessee and all PPL Energy Supply's interest in such
property and such lease agreement, whether or not such lease agreement
is intended as security;
. other Liens securing Debt the principal amount of which does not exceed
10% of the total assets of PPL Energy Supply and our consolidated
subsidiaries as shown on our most recent audited balance sheet; and
. Liens granted in connection with extending, renewing, replacing or
refinancing, in whole or in part, the Debt secured by liens described
above (to the extent of such Debt so extended, renewed, replaced or
refinanced).
(See Supplemental Indenture No.1, Article One, Sections 3, 4 and 10.)
CONSOLIDATION, MERGER AND CONVEYANCE OF ASSETS AS AN ENTIRETY. Subject to
the provisions described in the next paragraph, PPL Energy Supply has agreed in
the Indenture to preserve its corporate existence. (See Section 604.)
103
PPL Energy Supply has agreed not to consolidate with or merge into any other
entity or convey, transfer or lease its properties and assets substantially as
an entirety to any entity unless:
. the entity formed by such consolidation or into which PPL Energy Supply
merges or the entity which acquires or which leases the property and
assets of PPL Energy Supply substantially as an entirety is a
corporation or limited liability company organized and existing under
the laws of the United States of America or any State thereof or the
District of Columbia, and expressly assumes, by supplemental indenture,
the due and punctual payment of the principal, premium and interest on
all the outstanding Indenture Securities and the performance of all of
the covenants of PPL Energy Supply under the Indenture, and
. immediately after giving effect to such transactions, no Event of
Default, and no event which after notice or lapse of time or both would
become an Event of Default, will have occurred and be continuing. (See
Section 1101.)
TheIndenture does not prevent or restrict:
. any consolidation or merger after the consummation of which PPL Energy
Supply would be the surviving or resulting entity;
. any conveyance or other transfer, or lease, of any part of the
properties of PPL Energy Supply which does not constitute the entirety,
or substantially the entirety, thereof; or
. the approval by PPL Energy Supply of, or the consent by PPL Energy
Supply to, any consolidation or merger of any direct or indirect
subsidiary or affiliate or any conveyance, transfer or lease by any such
subsidiary or affiliate of any of its assets. (See Section 1103.)
The Indenture does not contain any financial covenants.
MODIFICATION OF INDENTURE
WITHOUT HOLDER CONSENT. Without the consent of any Holders of Indenture
Securities, we and the Trustee may enter into one or more supplemental
indentures for any of the following purposes:
. to evidence the succession of another entity to us;
. to add one or more covenants or other provisions for the benefit of the
Holders of all or any series or tranche of Indenture Securities, or to
surrender any right or power conferred upon us;
. to add any additional Events of Default for all or any series of
Indenture Securities;
. to change or eliminate any provision of the Indenture or to add any new
provision to the Indenture that does not adversely affect the interests
of the Holders;
. to provide security for the Indenture Securities of any series;
. to establish the form or terms of Indenture Securities of any series or
tranche as permitted by the Indenture;
. to provide for the issuance of bearer notes;
. to evidence and provide for the acceptance of appointment of a separate
or successor Trustee;
. to provide for the procedures required to permit the utilization of a
noncertificated system of registration for any series or tranche of
Indenture Securities;
. to change any place or places where
. we may pay principal, premium and interest,
. Indenture Securities may be surrendered for transfer or exchange, and
. notices and demands to or upon us may be served; or
. to cure any ambiguity, defect or inconsistency or to make any other
changes that do not adversely affect the interests of the Holders in any
material respect.
104
If the Trust Indenture Act is amended after the date of the Indenture so as
to require changes to the Indenture or so as to permit changes to, or the
elimination of, provisions which, at the date of the Indenture or at any time
thereafter, were required by the Trust Indenture Act to be contained in the
Indenture, the Indenture will be deemed to have been amended so as to conform
to such amendment or to effect such changes or elimination, and we and the
Trustee may, without the consent of any Holders, enter into one or more
supplemental indentures to effect or evidence such amendment.
(See Section 1201.)
WITH HOLDER CONSENT. Except as provided above, the consent of the Holders of
at least a majority in aggregate principal amount of the Indenture Securities
of all outstanding series, considered as one class, is generally required for
the purpose of adding to, changing or eliminating any of the provisions of the
Indenture pursuant to a supplemental indenture. However, if less than all of
the series of outstanding Indenture Securities are directly affected by a
proposed supplemental indenture, then such proposal only requires the consent
of the Holders of a majority in aggregate principal amount of the outstanding
Indenture Securities of all directly affected series, considered as one class.
Moreover, if the Indenture Securities of any series have been issued in more
than one tranche and if the proposed supplemental indenture directly affects
the rights of the Holders of Indenture Securities of one or more, but less than
all, of such tranches, then such proposal only requires the consent of the
Holders of a majority in aggregate principal amount of the outstanding
Indenture Securities of all directly affected tranches, considered as one class.
However, no amendment or modification may, without the consent of the Holder
of each outstanding Indenture Security directly affected thereby,
. change the stated maturity of the principal or interest on any Indenture
Security (other than pursuant to the terms thereof), or reduce the
principal amount, interest or premium payable or change the currency in
which any Indenture Security is payable, or impair the right to bring
suit to enforce any payment;
. reduce the percentages of Holders whose consent is required for any
supplemental indenture or waiver or reduce the requirements for quorum
and voting under the Indenture; or
. modify certain of the provisions in the Indenture relating to
supplemental indentures and waivers of certain covenants and past
defaults.
A supplemental indenture which changes or eliminates any provision of the
Indenture expressly included solely for the benefit of Holders of Indenture
Securities of one or more particular series or tranches will be deemed not to
affect the rights under the Indenture of the Holders of Indenture Securities of
any other series or tranche. (See Section 1202.)
We will be entitled to set any day as a record date for the purpose of
determining the Holders of outstanding Indenture Securities of any series
entitled to give or take any demand, direction, consent or other action under
the Indenture, in the manner and subject to the limitations provided in the
Indenture. In certain circumstances, the Trustee also will be entitled to set a
record date for action by Holders. If such a record date is set for any action
to be taken by Holders of particular Indenture Securities, such action may be
taken only by persons who are Holders of such Indenture Securities at the close
of business on the record date. (See Section 104.)
The Indenture provides that certain Indenture Securities, including those
for which payment or redemption money has been deposited or set aside in trust
as described under "--Satisfaction and Discharge" below, will not be deemed to
be "outstanding" in determining whether the Holders of the requisite principal
amount of the outstanding Indenture Securities have given or taken any demand,
direction, consent or other action under the Indenture as of any date, or are
present at a meeting of Holders for quorum purposes. (See Section 101.)
105
BOOK-ENTRY NOTES
DTC will act as the initial securities depositary for the new notes. The new
notes will be issued only as fully registered securities registered in the name
of Cede & Co., DTC's nominee. One or more fully registered global note
certificates will be issued, representing in the aggregate the total principal
amount of new notes, and will be deposited with the Trustee as custodian for
DTC. Except in the limited circumstances described under "--Certificated Notes"
below, beneficial interests in the global notes will only be recorded by
book-entry and owners of beneficial interests in the global notes will not be
entitled to receive physical delivery of certificates representing the new
notes. Accordingly, each beneficial owner must rely on the procedures of DTC to
exercise any rights under the new notes.
So long as DTC or its nominee is the Holder of a global note, DTC or its
nominee, as the case may be, will be considered the Holder of the new notes
represented by such Global Note for all purposes under the Indenture and the
new notes. No beneficial owner of an interest in a Global Note will be able to
transfer that interest except in accordance with DTC's applicable procedures
(in addition to those under the Indenture referred to herein and, if
applicable, those of Euroclear and Clearstream) unless we shall issue
certificates for the senior notes in definitive registered form as described
under "--Certificated Notes" below.
The following is based upon information furnished by DTC:
DTC is a limited-purpose trust company organized under the New York
Banking Law, 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 New York Uniform Commercial Code and
a "clearing agency" registered pursuant to the provisions of Section 17A of
the Securities Exchange Act of 1934, as amended. DTC holds securities that
its participants ("Participants") deposit with DTC. DTC also facilitates the
settlement among Participants of securities transactions, such as transfers
and pledges, in deposited securities through electronic computerized
book-entry changes in Participants' accounts, thereby eliminating the need
for physical movement of securities certificates. "Direct Participants" in
DTC include securities brokers and dealers, banks, trust companies, clearing
corporations and certain other organizations. DTC is owned by a number of
its Direct Participants and by The New York Stock Exchange, the American
Stock Exchange, Inc., and the National Association of Securities Dealers,
Inc. Access to the DTC system is also available to others, such as
securities brokers and dealers, banks and trust companies that clear
transactions through or maintain a custodial relationship with a Direct
Participant either directly or indirectly ("Indirect Participants"). The
rules applicable to DTC and its Participants are on file with the Securities
and Exchange Commission.
Issuance of new notes within the DTC system must be made by or through
Direct Participants, which will receive a credit for the new notes on DTC's
records. The ownership interest of each actual beneficial owner of each new
note ("Beneficial Owner") is in turn to be recorded on the Direct and
Indirect Participants' records. Beneficial Owners will not receive written
confirmation from DTC of their holdings, but Beneficial Owners are expected
to receive periodic statements of their holdings from the Direct or Indirect
Participants through which the Beneficial Owners entered into the
transaction. Transfers of ownership interests in the new notes are to be
accomplished by entries made on the books of Participants acting on behalf
of Beneficial Owners. Beneficial Owners will not receive certificates
representing their ownership interests in the new notes, except in the event
that use of the book-entry system for the new notes is discontinued, as
discussed below.
To facilitate subsequent transfers, all new notes deposited by
Participants with DTC are registered in the name of DTC's partnership
nominee, Cede & Co. The deposit of new notes with DTC and their registration
in the name of Cede & Co. effect no change in beneficial ownership. DTC has
no knowledge of the actual Beneficial Owners of the new notes; DTC's records
reflect only the identity of the Direct Participants to whose accounts such
new notes are credited, which may or may not be the Beneficial Owners. The
Participants will remain responsible for keeping account of their holdings
on behalf of their customers.
106
The delivery of notices and other communications by DTC to Direct
Participants, by Direct Participants to Indirect Participants, and by Direct
Participants and Indirect Participants to Beneficial Owners will be governed
by arrangements among them, subject to any statutory or regulatory
requirements as may be in effect from time to time.
Redemption notices will be sent to Cede & Co., as registered Holder of
the new notes. If less than all of the new notes are being redeemed, DTC's
practice is to determine by lot the amount of the interest of each Direct
Participant to be redeemed.
Neither DTC nor Cede & Co. will itself consent or vote with respect to
new notes. Under its usual procedures, DTC will mail an omnibus proxy to PPL
Energy Supply as soon as possible after the record date. The omnibus proxy
will assign Cede & Co.'s consenting or voting rights to those Direct
Participants to whose accounts the new notes are credited on the record date
(identified in a listing attached to the Omnibus Proxy).
Payments on the new notes will be made to DTC. DTC's practice is to
credit Direct Participants' accounts on the relevant payment date in
accordance with their respective holdings shown on DTC's records unless DTC
has reason to believe that it will not receive payment on such payment date.
Payments by Participants to Beneficial Owners will be governed by standing
instructions and customary practices, as is the case with securities held
for the accounts of customers in bearer form or registered in "street name,"
and will be the responsibility of such Participants and not of DTC or PPL
Energy Supply, subject to any statutory or regulatory requirements as may be
in effect from time to time. Payment to DTC will be the responsibility of
PPL Energy Supply, disbursement of payments to Direct Participants will be
the responsibility of DTC, and further disbursement of payments to the
Beneficial Owners will be the responsibility of Direct Participants and
Indirect Participants.
Transfers between participants in Euroclear and Clearstream will be effected
in the ordinary way in accordance with their respective rules and operating
procedures. Subject to compliance with the applicable transfer and exchange
restrictions described herein, cross-market transfers between DTC, on the one
hand, and directly or indirectly through Euroclear or Clearstream participants,
on the other, will be effected in DTC in accordance with DTC rules on behalf of
Euroclear or Clearstream as the case may be, by its respective depository;
however, such cross-market transactions will require delivery of instructions
to Euroclear or Clearstream, as the case may be, by the counterparty in such
system in accordance with its rules and procedures and within its established
deadlines. Euroclear or Clearstream, as the case may be, will, if the
transaction meets its settlement requirements, deliver instructions to its
respective depository to take action to effect final settlement on its behalf
by delivering or receiving interests in the relevant global note in DTC, and
making or receiving payment in accordance with normal procedures for same-day
funds settlement applicable to DTC. Euroclear and Clearstream participants may
not deliver instructions directly to the depositories for DTC.
Because of time zone differences, the securities account of a Euroclear or
Clearstream participant purchasing an interest in global notes from a DTC
participant will be credited during the securities settlement processing day
(which must be a business day for Euroclear or Clearstream, as the case may be)
immediately following the DTC settlement date, and such credit of any
transactions in interests in a Global Note settled during such processing day
will be reported to the relevant DTC participant on such day. Cash received in
Euroclear or Clearstream as a result of sales or interests in global notes by
or through a Euroclear or Clearstream participant to a DTC participant will be
received on the DTC settlement date, but will be available in the relevant
Euroclear or Clearstream cash account only as of the business day following
settlement in DTC.
Although DTC, Euroclear and Clearstream have agreed to the foregoing
procedures in order to facilitate transfer of interests in the new notes among
participants of DTC, Euroclear and Clearstream, they are under no obligation to
perform or continue to perform such procedures, and such procedures may be
discontinued at any time. Neither we nor the Trustee will have any
responsibility for the performance by DTC, Euroclear or Clearstream or their
respective participants or indirect participants or their respective
obligations as described in this prospectus or under the rules and procedures
governing their operations.
107
The information in this section concerning DTC and DTC's book-entry system
has been obtained from sources, including DTC, Euroclear and Clearstream, that
we believe to be reliable, but we take no responsibility for the accuracy of
that information.
CERTIFICATED NOTES
If:
. DTC or any successor depository notifies us that it is unwilling or
unable to continue as a depository for a Global Note or ceases to be a
"clearing agency" registered under the Exchange Act and a successor
depository is not appointed by us within 90 days of such notice, or
. we elect to discontinue use of the system of book-entry transfers
through DTC or a successor depository, we will issue certificates for
the new notes in definitive registered form in exchange for the Global
Notes. The Holder of a certificated definitive registered new note may
transfer such new note by surrendering it at the office or agency
maintained by us for such purpose in New York, New York, which initially
will be the office of the Trustee.
SATISFACTION AND DISCHARGE
Any Indenture Securities or any portion will be deemed to have been paid for
purposes of the Indenture, and at our election, our entire indebtedness will be
satisfied and discharged, if there shall have been irrevocably deposited with
the Trustee or any Paying Agent (other than us), in trust:
. money sufficient,
. in the case of a deposit made prior to the maturity of such Indenture
Securities, non-redeemable Government Obligations (as defined in the
Indenture) sufficient, or
. a combination of items listed in the preceding two items, which in total
are sufficient,
to pay when due the principal of, and any premium, and interest due and to
become due on such Indenture Securities or portions thereof on and prior to the
maturity thereof.
(See Section 701.)
The Indenture will be deemed satisfied and discharged when no Indenture
Securities remain outstanding and when we have paid all other sums payable by
us under the Indenture. (See Section 702.)
All moneys we pay to the Trustee or any Paying Agent on new notes which
remain unclaimed at the end of two years after payments have become due may be
paid to or upon our order. Thereafter, the Holder of such new note may look
only to us for payment. (See Section 603.)
RESIGNATION AND REMOVAL OF THE TRUSTEE; DEEMED RESIGNATION
The Trustee may resign at any time by giving written notice to us.
The Trustee may also be removed by act of the Holders of a majority in
principal amount of the then outstanding Indenture Securities of any series.
No resignation or removal of the Trustee and no appointment of a successor
trustee will become effective until the acceptance of appointment by a
successor trustee in accordance with the requirements of the Indenture.
Under certain circumstances, we may appoint a successor trustee and if the
successor accepts, the Trustee will be deemed to have resigned. (See Section
910)
108
NOTICES
Notices to Holders of new notes will be given by mail to the addresses of
the Holders as they may appear in the security register. (See Section 106).
TITLE
PPL Energy Supply, the Trustee, and any agent of PPL Energy Supply or the
Trustee, will treat the person or entity in whose name new notes are registered
as the absolute owner of those new notes (whether or not the new notes may be
overdue) for the purpose of making payments and for all other purposes
irrespective of notice to the contrary. (See Section 308).
GOVERNING LAW
The Indenture and the new notes provide that they will be governed by and
construed in accordance with the laws of the State of New York, except to the
extent the Trust Indenture Act shall be applicable or the law of another
juristiction shall mandatorily govern. (See Section 112.)
REGARDING THE TRUSTEE
The Trustee under the Indenture is The Chase Manhattan Bank. In addition to
acting as Trustee, The Chase Manhattan Bank also maintains various banking and
trust relationships with us and some of our affiliates.
109
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
This section describes the material United States federal income tax
consequences of exchanging the old notes for new notes and of owning and
disposing of notes. This section reflects the opinion of Thelen Reid & Priest
LLP, counsel to PPL Energy Supply. This section applies to you only if you
acquired the old notes in the offering at the offering price and you hold your
notes as capital assets for tax purposes. This section does not apply to you if
you are a member of a class of holders subject to special rules, such as:
. dealer in securities or currencies,
. trader in securities that elects to use a mark-to-market method of
accounting for your securities holdings,
. bank,
. life insurance company,
. tax-exempt organization,
. person that owns notes that are a hedge or that are hedged against
interest rate risks,
. person that owns notes as part of a straddle or conversion transaction
for tax purposes, or
. person whose functional currency for tax purposes is not the U.S. dollar.
If you purchase notes at a price other than the offering price, the
amortizable bond premium or market discount rules may also apply to you. You
should consult your tax advisor regarding this possibility.
This section is based on the Internal Revenue Code of 1986, as amended, its
legislative history, existing and proposed regulations under the Internal
Revenue Code, published rulings and court decisions, all as currently in
effect. These authorities are subject to change, possibly on a retroactive
basis. This section does not discuss all aspects of taxation that may be
relevant to you. Accordingly, you should consult your tax advisor as to the
application and effect of state and local taxes and other tax laws.
UNITED STATES HOLDERS
This subsection describes the tax consequences to a United States holder.
You are a United States holder if you are a beneficial owner of a new note and
you are:
. citizen or resident of the United States,
. domestic corporation or partnership,
. estate whose income is subject to United States federal income tax
regardless of its source, or
. trust if a United States court can exercise primary supervision over the
trust's administration and one or more United States persons are
authorized to control all substantial decisions of the trust.
If you are not a United States holder, this subsection does not apply to you
and you should refer to "United States Alien Holders" below.
EXCHANGE OF OLD NOTES FOR NEW NOTES
An exchange of old notes for new notes will not be a taxable event for
federal income tax purposes. Rather, the new notes will be treated as a
continuation of the old notes in the hands of a United States holder. As a
result, you will not recognize any income, gain or loss for federal income tax
purposes upon an exchange of old notes for new notes, and you will have the
same tax basis and holding period in the new notes as you had in the old notes.
PAYMENTS OF INTEREST
You will be taxed on interest on your new notes as ordinary income at the
time you receive the interest or when it accrues, depending on your method of
accounting for tax purposes.
110
PURCHASE, SALE AND RETIREMENT OF THE NEW NOTES
Your tax basis in your old notes generally will be their cost, and your tax
basis in any new notes acquired in the exchange offer will be equal to your tax
basis in the old notes surrendered. You will generally recognize capital gain
or loss on the sale or retirement of new notes equal to the difference between
the amount you realize on the sale or retirement, excluding any amounts
attributable to accrued but unpaid interest, and your tax basis in your new
notes. Capital gain of a noncorporate United States holder is generally taxed
at a maximum rate of 20% where the property is held more than one year.
UNITED STATES ALIEN HOLDERS
This subsection describes the tax consequences to a United States alien
holder. You are a United States alien holder if you are the beneficial owner of
a new note and are, for United States federal income tax purposes:
. nonresident alien individual,
. foreign corporation,
. foreign partnership,
. estate unless its income is subject to United States federal income tax
regardless of its source, or
. trust unless a United States court can exercise primary supervision over
the trust's administration and one or more United States persons are
authorized to control all substantial decisions of the trust.
If you are a United States holder, this section does not apply to you.
An exchange of old notes for new notes will not constitute a taxable event
for federal income tax purposes. Rather, the new notes will be treated as a
continuation of the old notes in the hands of a United States alien holder. As
a result, you will not recognize any income, gain or loss for federal income
tax purposes upon an exchange of old notes for new notes, and you will have the
same tax basis and holding period in the new notes as you had in the old notes.
Under United States federal income and estate tax law, and subject to the
discussion of backup withholding below, if you are a United States alien holder
of a note:
. we and other U.S. payors generally will not be required to deduct United
States withholding tax from payments of principal, premium, if any, and
interest to you if, in the case of payments of interest:
. you do not actually or constructively own 10% or more of the total
combined voting power of all classes of stock of PPL Energy Funding
entitled to vote,
. you are not a controlled foreign corporation that is related to PPL
Energy Funding through stock ownership,
. your income or gain from the new note is not effectively connected
with a trade or business that you conduct within the United States,
and
. either (1) you furnish the U.S. payor an Internal Revenue Service
Form W-8BEN certifying under penalties of perjury that you are not a
United States person, or (2) the payor can otherwise be satisfied
that you are not a United States person by relying on account
documentation or other evidence as prescribed in Treasury
regulations. However, this requirement will not be considered
satisfied if the payor has actual knowledge or reason to know that
you are a United States person notwithstanding the certificate or
other documentation.
. no deduction for any United States federal withholding tax will be made
from any gain that you realize on the sale or exchange of your new note,
including the exchange of old notes for new notes.
111
We and other payors are required to report payments of interest on your new
notes on Internal Revenue Service Form 1042-S even if the payments are not
otherwise subject to information reporting requirements.
If you are engaged in a trade or business within the United States and the
interest on the new note is effectively connected with your United States
business, the interest and any gain on the new note will not be subject to
withholding if you have provided the payor an Internal Revenue Service Form W-8
as prescribed in the Treasury regulations. However, interest on a new note that
is effectively connected with your United States business will be subject to
United States taxation in the same manner as applies to United States holders.
In addition, if you are entitled to the benefits of a tax treaty with the
United States, interest and gain from the new note will generally not be
taxable, even if effectively connected with a United States trade or business,
unless you also have a permanent establishment in the United States to which
the interest or gain is attributable. In order to claim benefits under a tax
treaty with the United States, you must furnish an Internal Revenue Service
Form W-8BEN to the payor.
Further, a new note held by an individual who at death is not a citizen or
resident of the United States will not be includible in the individual's gross
estate for United States federal estate tax purposes if:
. the decedent did not actually or constructively own 10% or more of the
total combined voting power of all classes of stock of PPL Energy
Funding entitled to vote at the time of death, and
. the income on the new note would not have been effectively connected
with a United States trade or business of the decedent at the same time.
BACKUP WITHHOLDING AND INFORMATION REPORTING
We and other payors, including brokers, may be required to report to you and
to the Internal Revenue Service any payments of principal, premium and interest
on your new note and the amount of any proceeds from the sale or exchange of
your new note. As described more fully below, we and other payors may also be
required to make "backup withholding" from payments of principal, premium,
interest and sales proceeds if you fail to provide an accurate taxpayer
identification number or otherwise establish an exemption from backup
withholding.
Backup withholding is not an additional tax. If you are subject to backup
withholding, you may obtain a credit or refund of the amount withheld by filing
the required information with the Internal Revenue Service.
UNITED STATES HOLDERS
In general, if you are a noncorporate United States holder, we and other
payors are required to report to the Internal Revenue Service all payments of
principal, any premium and interest on your new note. In addition, we and other
payors are required to report to the Internal Revenue Service any payment of
proceeds of the sale of your new note before maturity within the United States.
Additionally, backup withholding at a rate of 30.5% (30% for amounts paid after
December 31, 2000) will apply to any payments if you fail to provide an
accurate taxpayer identification number, or you are notified by the Internal
Revenue Service that you have failed to report all interest and dividends
required to be shown on your federal income tax returns.
UNITED STATES ALIEN HOLDERS
In general, payments of principal, premium or interest made by us and other
payors to you will not be subject to backup withholding and information
reporting, provided that the certification requirements described above under
"United States Alien Holders" are satisfied or you otherwise establish an
exemption.
In general, proceeds of your sale of a new note will not be subject to
backup withholding or information reporting if:
. you furnish your broker an Internal Revenue Service Form W-8BEN
certifying under penalties of perjury that you are not a United States
person, or
112
. your broker possesses other documentation concerning your account on
which the broker is permitted to rely under Treasury regulations to
establish that you are a non-United States person, or
. you otherwise establish an exemption.
If you are not exempted from backup withholding and information reporting
under the preceding paragraph:
. Backup withholding and information reporting will apply to the proceeds
of any sale that you make through the United States office of any
broker, foreign or domestic.
. Information reporting will also apply to the proceeds of sales that are
made through a foreign office of a broker if the proceeds are paid into
a United States account, or such proceeds or the confirmation of the
sale are mailed to you at a United States address, or if you have opened
an account with a United States office of your broker, or regularly
communicated with the broker from the United States concerning the sale
in question and other sales, or negotiated the sale in question through
the broker's United States office. Backup withholding will also apply
unless the proceeds of such a sale are paid to an account maintained at
a bank or other financial institution located outside the United States.
. Information reporting, but not backup withholding, will apply to sales
made through a foreign office of a broker that is a United States
person, or that is a controlled foreign corporation or partnership
controlled by U.S. persons or that derives more than 50% of its income
from U.S. business activities over a three-year period as specified in
the Treasury regulations.
Notwithstanding any withholding certificate or documentary evidence in a
broker's possession, a broker who has actual knowledge or reason to know that
you are a United States person will be required to make backup withholdings and
file information reports with the Internal Revenue Service if the broker is a
U.S. person or is a foreign person that has a U.S. connection of the type
discussed in the last bullet point of the preceding paragraph.
113
PLAN OF DISTRIBUTION
As discussed under "The Exchange Offer," based on an interpretation of the
staff of the SEC, new notes issued pursuant to the exchange offer may be
offered for resale and resold or otherwise transferred by a holder of such new
notes (other than any such holder which is an "affiliate" of PPL Energy Supply
within the meaning of Rule 405 under the Securities Act and except as otherwise
discussed below with respect to holders which are broker-dealers) without
compliance with the registration and prospectus delivery requirements of the
Securities Act so long as such new notes are acquired in the ordinary course of
such holder's business and such holder has no arrangement or understanding with
any person to participate in the distribution (within the meaning of the
Securities Act) of such new notes.
Each broker-dealer that receives new notes for its own account pursuant to
the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of such new notes. 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 notes received in exchange for old notes where
such old notes 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
consummation of registered exchange offer, we will make this prospectus, as
amended or supplemented, available to any broker-dealer for us in connection
with any such resale. In addition, until , 200_, all dealers
effecting transactions in the new notes may be required to deliver a prospectus.
We will not receive any proceeds from any sale of new notes by
broker-dealers. New notes received by broker-dealers for their own account
pursuant to the 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 notes 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 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 notes. Any broker-dealer that
resells new notes that were received by it for its own account pursuant to the
exchange offer and any broker or dealer that participated in a distribution of
such new notes may be deemed to be an "underwriter" within the meaning of the
Securities Act and any profit on any such resale of new notes 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 consummation of a registered exchange
offer, 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 with the initial
purchasers to pay expenses incident to the exchange offer (including the
expenses of one counsel for the holders of the old notes) other than
commissions or commissions of any brokers or dealers and will indemnify the
holders of the old notes (including any broker-dealers) against certain
liabilities, including liabilities under the Securities Act.
By acceptance of this exchange offer, each broker-dealer that receives new
notes for its own account pursuant to the exchange offer agrees that, upon
receipt of notice from us of the happening of any event which makes any
statement in the prospectus untrue in any material respect or requires the
making of any changes in the prospectus in order to make the statements therein
not misleading (which notice we agree to deliver promptly to such
broker-dealer), such broker-dealer will suspend use of the prospectus until we
have amended or supplemented the prospectus to correct such misstatement or
omission and have furnished copies of the amended or supplemental prospectus to
such broker dealer.
The interpretation of the staff of the SEC referred to in the first
paragraph of this section does not apply to, and this prospectus may not be
used in connection with, the resale by any broker-dealer of any new notes
received in exchange for an unsold allotment of old notes purchased directly
from us.
114
EXPERTS
The Summary Independent Technical Review included as Annex A to this
prospectus has been prepared by Stone & Webster Consultants, Inc. and is
included in this prospectus in reliance upon the authority of Stone & Webster
Consultants, Inc. and its affiliates as experts in the review of the design and
operation of electric generation facilities. The Independent Market
Consultant's Report included as Annex B to this prospectus has been prepared by
ICF Resources, Inc. and is included in this prospectus in reliance upon the
authority of that firm as experts in the analysis of power markets, including
future market demand, future market prices for electric energy and capacity and
related matters, for electric generation facilities.
The PPL Energy Supply consolidated financial statements as of December 31,
2000 and 1999, and for the three years ended December 31, 2000, included in
this prospectus have been audited by PricewaterhouseCoopers LLP, independent
accountants, as stated in their report herein, and are included in reliance
upon the report of such firm given upon their authority as experts in
accounting and auditing. The Hyder Plc consolidated financial statements as of
March 31, 2000 and 1999, and for the three years ended March 31, 2000, included
in this prospectus have been audited by PricewaterhouseCoopers, Cardiff, United
Kingdom, independent accountants, as stated in their report herein, and are
included in reliance upon the report of such firm given upon their authority as
experts in accounting and auditing.
The SIUK plc consolidated financial statements as of March 31, 2001 and
2000, and for the three years ended March 31, 2001, included in this prospectus
have been audited by Arthur Andersen, independent accountants, as indicated in
their reports with respect thereto, and are included herein in reliance upon
the authority of said firm as experts in accounting and auditing in giving said
reports.
VALIDITY OF THE NEW NOTES
Michael A. McGrail, Esq., Senior Counsel of PPL Services Corporation, and
Thelen Reid & Priest LLP, New York, New York, counsel to PPL Energy Supply,
will pass upon the validity of the new notes. As to matters involving the law
of the State of New York, Mr. McGrail will rely on the opinion of Thelen Reid &
Priest LLP.
115
INDEX TO FINANCIAL STATEMENTS
PAGE
PPL ENERGY SUPPLY: AUDITED FINANCIAL STATEMENTS -----
REPORT OF INDEPENDENT ACCOUNTANTS....................................... F-2
CONSOLIDATED BALANCE SHEET AT DECEMBER 31, 2000 AND 1999................ F-3
CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED 2000, 1999 AND 1998 F-5
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED 2000, 1999, AND
1998.................................................................. F-6
CONSOLIDATED STATEMENT OF MEMBER'S EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED 2000, 1999 AND 1998............................... F-7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, DECEMBER 31, 2000........... F-8
PPL ENERGY SUPPLY: UNAUDITED INTERIM FINANCIAL STATEMENTS*
CONDENSED CONSOLIDATED BALANCE SHEET AT SEPTEMBER 30, 2001 AND
DECEMBER 31, 2000..................................................... F-38
CONDENSED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE
MONTHS ENDED SEPTEMBER 30, 2001 AND 2000.............................. F-40
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 2001 AND 2000..................................... F-41
CONDENSED CONSOLIDATED STATEMENT OF MEMBER'S EQUITY AND COMPREHENSIVE
INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000 F-42
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS,
SEPTEMBER 30, 2001.................................................... F-43
PPL ENERGY SUPPLY: FINANCIAL STATEMENTS OF AFFILIATES
OVERVIEW OF FINANCIAL STATEMENTS OF AFFILIATES.......................... F-59
FINANCIAL STATEMENTS OF HYDER, PLC, YEAR ENDED MARCH 31, 2000........... F-60
FINANCIAL STATEMENTS OF SIUK PLC, YEAR ENDED MARCH 31, 2001............. F-127
PPL ENERGY SUPPLY: SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND
RESERVES
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE....... F-147
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES............. F-148
* These interim financial statements are dated November 13, 2001.
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Managers and
Sole Member of PPL Energy Supply, LLC
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, member's equity and comprehensive income and
cash flows present fairly, in all material respects, the financial position of
PPL Energy Supply, LLC and its subsidiaries at December 31, 2000 and 1999, and
the results of their operations and their cash flows for the three years ended
December 31, 2000 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
June 15, 2001
F-2
PPL ENERGY SUPPLY, LLC
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2000 AND 1999
(MILLIONS OF DOLLARS)
2000 1999
------ ------
ASSETS
CURRENT ASSETS
Cash and cash equivalents (Note 1).................................. $ 130 $ 82
Accounts receivable (less reserve: 2000, $52; 1999, $3)............. 355 158
Accounts receivable from affiliated companies (Note 14)............. 128 282
Unbilled revenues (Note 1).......................................... 142 55
Notes receivable from affiliated companies (Note 14)................ 1,279
Fuel, materials and supplies--at average cost....................... 154 12
Prepayments......................................................... 31 8
Unrealized energy trading gains (Note 1)............................ 79
Other............................................................... 84 25
------ ------
2,382 622
------ ------
INVESTMENTS
Investments in unconsolidated affiliates--at equity (Notes 1 and 3). 800 407
Investments in unconsolidated affiliates--at cost (Note 1).......... 46
Nuclear plant decommissioning trust fund (Note 6)................... 268
Other............................................................... 4
------ ------
1,118 407
------ ------
PROPERTY, PLANT AND EQUIPMENT (NOTE 1)................................. 3,389 1,235
------ ------
OTHER NONCURRENT ASSETS
Goodwill, net (Note 1).............................................. 452 371
Deferred income taxes............................................... 59 3
Other............................................................... 63 83
------ ------
574 457
------ ------
$7,463 $2,721
====== ======
The accompanying notes are an integral part of these financial statements.
F-3
PPL ENERGY SUPPLY, LLC
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2000 AND 1999
(MILLIONS OF DOLLARS)
2000 1999
------ ------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt........................................... $ 170 $ 378
Short-term debt payable to affiliated companies (Note 14). 2,120 863
Long-term debt (Note 8)................................... 33 5
Accounts payable.......................................... 380 117
Accounts payable to affiliated companies (Note 14)........ 169 90
Above market NUG contracts (Note 13)...................... 93
Wholesale energy commitments (Note 13).................... 23 16
Taxes..................................................... 145 25
Dividends................................................. 93
Unrealized energy trading losses (Note 1)................. 84
Other..................................................... 46 23
------ ------
3,356 1,517
------ ------
LONG-TERM DEBT (NOTE 8)...................................... 159 33
------ ------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Deferred income taxes and investment tax credits.......... 82
Above market NUG contracts (Note 13)...................... 581
Wholesale energy commitments (Note 13).................... 76 81
Nuclear plant decommissioning (Note 6).................... 280
Other..................................................... 298 104
------ ------
1,317 185
COMMITMENTS AND CONTINGENT LIABILITIES (NOTE 13).............
------ ------
MINORITY INTEREST (NOTE 1)................................... 54 64
------ ------
MEMBER'S EQUITY.............................................. 2,577 922
------ ------
$7,463 $2,721
====== ======
The accompanying notes are an integral part of these financial statements.
F-4
PPL ENERGY SUPPLY, LLC
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(MILLIONS OF DOLLARS)
2000 1999 1998
------ ------ ----
OPERATING REVENUES
Wholesale energy marketing and trading.......................... $1,827 $ 46
Retail electric and gas......................................... 879 661
Energy related businesses (Note 1).............................. 347 209 $ 78
Equity in earnings of unconsolidated affiliates (Notes 1 and 3). 68 58 47
------ ------ ----
3,121 974 125
------ ------ ----
OPERATING EXPENSES
Operation
Fuel........................................................ 269 2
Energy purchases............................................ 1,378 754
Other operation and maintenance............................. 475 50 20
Transmission................................................ 54 1
Depreciation and amortization (Note 1).......................... 89 20 1
Taxes, other than income (Note 5)............................... 53 19
Project development (Note 1).................................... 16 2 5
Energy related businesses (Note 1).............................. 323 207 78
------ ------ ----
2,657 1,055 104
------ ------ ----
OPERATING INCOME (LOSS)............................................ 464 (81) 21
Other Income--net.................................................. 34 83 10
------ ------ ----
INCOME BEFORE INTEREST EXPENSE, INCOME TAXES AND MINORITY INTEREST. 498 2 31
Interest Expense................................................... 127 52 25
------ ------ ----
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST................... 371 (50) 6
Income Taxes (Note 5).............................................. 125 (29) (6)
Minority Interest (Note 1)......................................... 4 14
------ ------ ----
NET INCOME (LOSS).................................................. $ 242 $ (35) $ 12
====== ====== ====
The accompanying notes are an integral part of these financial statements.
F-5
PPL ENERGY SUPPLY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(MILLIONS OF DOLLARS)
2000 1999 1998
------- ------- -----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)..................................................... $ 242 $ (35) $ 12
Adjustments to reconcile net income to net cash provided by operating
activities
Depreciation and goodwill amortization............................ 89 20 1
Amortization--energy commitments (Note 13)........................ (68)
Gain on sale of electric energy projects.......................... (78)
Minority interest................................................. 4 14
Impairment of investments in electric energy projects............. 51
Equity in earnings of unconsolidated affiliates................... (68) (58) (47)
Deferred income taxes and investment tax credits.................. (19) 26 1
Change in current assets and current liabilities
Accounts receivable............................................... (9) (254) (28)
Accounts payable.................................................. 242 32 40
Other--net........................................................ 201 28
Other operating activities--net....................................... 1 5 35
------- ------- -----
Net cash provided by (used in) operating activities...................... 615 (249) 14
------- ------- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment........................ (280) (37) (1)
Sale of electric energy projects...................................... 123
Proceeds from sale/leaseback of generating assets..................... 410
Investment in generating assets and electric energy projects.......... (575) (1,066) (306)
Sales and maturities of available-for-sale securities................. 70
Purchase of available-for-sale securities............................. (15)
Net (increase) decrease in notes receivable from affiliates........... (914) 54 (54)
Other investing activities--net....................................... 8 1
------- ------- -----
Net cash used in investing activities.................................... (1,351) (926) (305)
------- ------- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt.......................................... (42) (145) (3)
Contributions from Member............................................. 17 643 29
Distributions to Member............................................... (142)
Net increase (decrease) in short-term debt............................ (180) 362 (2)
Net increase in short-term debt payable to affiliates................. 1,122 341 280
Other financing activities--net....................................... 9
------- ------- -----
Net cash provided by financing activities................................ 784 1,201 304
------- ------- -----
NET INCREASE IN CASH AND CASH EQUIVALENTS 48 26 13
Cash and Cash Equivalents at Beginning of Period...................... 82 56 43
------- ------- -----
Cash and Cash Equivalents at End of Period............................ $ 130 $ 82 $ 56
======= ======= =====
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 27
Income taxes.......................................................... $ 117 $ (64) $ 1
NON-CASH CONTRIBUTIONS FROM MEMBER:
Net assets transferred in corporate realignment (Note 15)............. $ 1,588
Property, equipment, financing and acquisition costs (Note 9)......... $ 23
The accompanying notes are an interal part of these financial statements.
F-6
PPL ENERGY SUPPLY, LLC
CONSOLIDATED STATEMENT OF MEMBER'S EQUITY AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(MILLIONS OF DOLLARS)
2000 1999 1998
------ ---- ----
Member's equity--beginning of year.......................... $ 922 $297 $224
Member's contributions................................... 1,540 711 62
Net income (loss)........................................ 242 (35) 12
Other comprehensive income, net of tax:
Foreign currency translation adjustments............. 15 (51) 1
Unrealized loss on available-for-sale securities..... (2)
Distributions to Member.................................. (142)
------ ---- ----
Member's equity--end of year................................ $2,577 $922 $297
====== ==== ====
Statement of Comprehensive Income (loss):
Net income (loss)........................................ $ 242 $(35) $ 12
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments............. 15 (51) 1
Unrealized loss on available-for-sale securities..... (2)
------ ---- ----
Total other comprehensive income (loss).................. 15 (51) (1)
------ ---- ----
Comprehensive income (loss).............................. $ 257 $(86) $ 11
====== ==== ====
The accompanying notes are an integral part of these financial statements.
F-7
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998
Terms and abbreviations appearing in these Notes to Consolidated Financial
Statements are explained in the Glossary of Terms and Abbreviations.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
PPL Energy Supply is an indirect wholly-owned subsidiary of PPL. PPL Energy
Supply was formed as a subsidiary of PPL Energy Funding in November 2000, to
engage in competitive energy businesses. PPL Energy Funding is the sole Member
of PPL Energy Supply. PPL Energy Supply is the parent of PPL Generation, PPL
EnergyPlus, PPL Global and PPL Investment Corporation. In May 2001, PPL Energy
Funding contributed its interests in PPL Generation, PPL EnergyPlus and PPL
Global to PPL Energy Supply, after receipt of required regulatory approvals.
The principal business of PPL Generation is owning and operating U.S.
generating facilities through various subsidiaries. The principal business of
PPL EnergyPlus is wholesale and unregulated retail energy marketing. PPL
Global's principal businesses are the acquisition and development of both U.S.
and international energy projects, and the ownership and operation of
international energy projects. PPL Investment Corporation makes loans to
subsidiaries of PPL Energy Supply.
PREDECESSOR BUSINESSES AND BASIS OF PRESENTATION
PPL Energy Supply intends to file a registration statement with the SEC
under the Securities Act of 1933. The SEC requires financial information of the
registrant's predecessors for all periods prior to the registrant's existence.
The following business and asset acquisitions were identified as predecessors
to PPL Energy Supply:
1950--Realty Company of Pennsylvania
1960--Lady Jane Colleries, Inc.
1968--Pennsylvania Mines Corporation
1975--Greene Manor Coal Company
1976--PPL Interstate Energy Company
1977--BDW Corporation
1995--PPL Global, LLC; PPL Spectrum, Inc.
1998--PPL EnergyPlus, LLC; H.T. Lyons, Inc.; McClure Company
1999--generation assets acquired from Montana Power (forming PPL Montana, LLC);
PPL Rights, Inc.; Burns Mechanical, Inc.; McCarl's Inc.; PPL Energy
Services Northeast, Inc. (formerly Western Mass. Holdings, Inc.); PPL
Synfuel Investments, LLC; PPL Somerset, LLC; PPL Maine, LLC
2000--Clymer Fuel, LLC; and generation assets transferred by PPL Electric
Utilities in the July 1, 2000 corporate realignment (formed as
subsidiaries of PPL Generation, LLC. See Note 15).
Since acquisition or formation, each entity identified above remained a
wholly-owned subsidiary of PPL or its subsidiaries. Therefore, the entities
listed above have been combined as one collective predecessor for purposes of
satisfying SEC financial statement requirements, based on their respective
acquisition or formation dates. In the balance of these notes, "PPL Energy
Supply" refers to the predecessors of PPL Energy Supply as presented above.
Certain line items in these PPL Energy Supply financial statements may not
agree with the financial statements previously issued by PPL in connection with
its reports pursuant to the Securities Exchange Act of 1934, due to
reclassifications, as well as eliminations at different levels of consolidation.
F-8
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
CONSOLIDATION
PPL Energy Supply consolidates the financial statements of its affiliates
when it has a controlling ownership. All significant intercompany transactions
have been eliminated.
Investments in affiliates in which PPL Energy Supply has the ability to
exercise significant influence over the operating and financial policies, but
not control, are accounted for using the equity method. In addition, majority
or jointly-owned affiliates where control does not exist are accounted for
using the equity method. Under the equity method of accounting, the investment
is recorded at historical cost and adjusted for PPL Energy Supply's share of
undistributed earnings or losses.
Investments in which PPL Energy Supply does not have the ability to exercise
significant influence and which it does not control are accounted for using the
cost, or fair value, method. Under this method of accounting, the investment is
recorded at historical cost and no undistributed earnings or losses are
recorded. Dividends are recorded in income when received.
The consolidated financial statements reflect the accounts of all controlled
affiliates on a current basis, with the exception of certain PPL Global
investments. PPL Global consolidates foreign affiliates on a lag, based on the
availability of financial data on a U.S. GAAP basis. PPL Global consolidates
the results of Emel, EC, its Bolivian subsidiaries and other consolidated
investments on a one-month lag. The results of CEMAR are consolidated on a
three-month lag.
PPL Global also records equity in earnings of unconsolidated international
affiliates on a lag. Earnings from WPDH and WPDL are recorded on a one-month
lag. PPL Global has 51% equity ownership interests in these entities but has
joint control of these investments with Mirant. Earnings from all other
international equity method investments are recorded on a three-month lag.
When the ownership interest in an affiliate increases through a series of
acquisitions and subsequently results in control, the equity method of
accounting ceases to apply. In accordance with Accounting Research Bulletin 51,
"Consolidated Financial Statements," the affiliate's results are included in
the consolidated financial statements as though it were acquired at the
beginning of the year.
USE OF ESTIMATES
The preparation of financial statements in conformity with U.S. GAAP
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements, and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates.
F-9
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
PROPERTY, PLANT AND EQUIPMENT
Following are the classes of PPL Energy Supply property, plant and
equipment, with associated accumulated depreciation reserves, at December 31
(millions of dollars):
2000 1999
------- ------
Property, plant and equipment
Electric utility plant
Generation..................... $ 6,802 $ 828
Transmission and distribution.. 769 262
Nuclear fuel................... 320
Construction work in progress.. 226 38
General........................ 149 32
Gas and oil....................... 67 67
Other property.................... 93 88
------- ------
8,426 1,315
Less: Accumulated depreciation.... (5,037) (80)
------- ------
Property, plant and equipment--net $ 3,389 $1,235
------- ------
Property, plant and equipment is generally recorded at cost. Certain
generation assets transferred from PPL Electric had been written down to market
value due to impairment, as part of PPL Electric's 1998 restructuring
settlement order in connection with the Pennsylvania Customer Choice Act. At
that point those assets were no longer subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation." Property, plant
and equipment acquired as part of business acquisitions is recorded at the fair
market value at acquisition date. Certain classes of property, plant and
equipment, including transmission and distribution plant, as well as items
capitalized subsequent to an acquisition, are recorded at historical cost.
PPL Energy Supply periodically reviews the depreciable lives of its fixed
assets. In conjunction with the corporate realignment (see Note 15), studies
were conducted of depreciable lives of certain generation assets. These studies
indicated that the estimated economic lives for certain generation assets were
longer than the lives used to calculate depreciation for financial statement
purposes. Therefore, effective July 1, 2000, PPL Energy Supply revised the
estimated economic lives for fossil generation and pipeline assets. The effect
of this change in 2000 was to reduce depreciation expense by $17 million and
increase net income by approximately $10 million.
Capitalized interest is recorded for construction projects in accordance
with SFAS 34, "Capitalization of Interest Cost."
When plant is retired or sold, the costs of such assets and the related
accumulated depreciation are removed from the balance sheet and the gain or
loss, if any, is included in income. The cost of repairs and replacements are
charged to expense as incurred.
Depreciation is computed over the estimated useful lives of property using
various methods including the straight-line, composite, and group methods. The
annual provisions for depreciation have been computed principally in accordance
with the following ranges of asset lives: generation, 5 - 50 years;
transmission and distribution, 30 - 40 years; general, 10 - 58 years.
F-10
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
NUCLEAR DECOMMISSIONING AND FUEL DISPOSAL
An annual provision for PPL Susquehanna's share of the future cost to
decommission the Susquehanna station, equal to the amount allowed in PPL
Electric's customer rates, is charged to depreciation expense. Such amounts are
invested in external trust funds, which can be used only for future
decommissioning costs. See Note 6 for additional information.
ACCOUNTING FOR PRICE RISK MANAGEMENT
PPL Energy Supply 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." In
1999 and 2000, PPL EnergyPlus entered into commodity forward and financial
contracts for the physical purchase and sale of energy as well as energy
contracts that can be settled financially. In 1998, these instruments were
reflected in the financial statements using the accrual method of accounting.
As of January 1, 1999, PPL EnergyPlus adopted mark-to-market accounting for
energy trading contracts, in accordance with EITF 98-10. Gains and losses from
changes in market prices are reflected in "Energy purchases" on the
Consolidated Statement of Income, and in "Unrealized energy trading gains" and
"Unrealized energy trading losses" on the Consolidated Balance Sheet.
PPL EnergyPlus accounts for its commodity forward and financial contracts in
accordance with EITF 98-10 and adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended, on January 1, 2001. See Note
16 for additional information.
Through PPL, PPL Energy Supply enters into interest rate derivative
contracts to hedge its exposure to changes in the fair value of assets or
liabilities, and its exposure to variability in expected cash flows associated
with existing assets or liabilities, or forecasted transactions. Prior to
adopting SFAS 133, gains or losses on these derivatives were deferred and were
being recognized over the life of the debt, in accordance with SFAS 80,
"Accounting for Futures Contracts."
Through PPL, PPL Energy Supply also enters into foreign currency derivative
contracts to hedge foreign currency exposures including firm commitments,
recognized assets or liabilities, forecasted transactions or net investments.
Prior to adopting SFAS 133, market gains and losses were recognized in
accordance with SFAS 52, "Foreign Currency Translation," and were included in
"Other comprehensive income (loss)" on the Consolidated Statement of Member's
Equity and Comprehensive Income.
LEASES
In July 2000, PPL Montana sold its investment in the Colstrip Steam
Generation electric plant to owner lessors, who are leasing the assets back to
PPL Montana under four 36-year operating leases. The proceeds from the sale
approximated $410 million. A gain of approximately $8 million was deferred, and
is being amortized over the life of the lease. PPL Montana used the proceeds to
reduce outstanding debt and make distributions to PPL Generation. PPL Montana
leases a 50% interest in the Colstrip Units 1 and 2 and a 30% interest in Unit
3, through the non-cancelable operating leases. The leases provide two renewal
options based on the economic useful life of the generation assets. The leases
place certain restrictions on PPL Montana's ability to incur additional debt,
sell assets and declare dividends, and require PPL Montana to maintain certain
financial ratios related to cash flow and net worth. Future minimum lease
payments are estimated as follows (millions of dollars): 2001, $43; 2002, $49;
2003, $47; 2004, $44; 2005, $38; and thereafter, $531.
F-11
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
Payments on other leased property, which are classified as operating leases
at December 31, 2000, are projected at $8 million per year through 2005. These
leases include vehicles, office space, computer equipment, and other operating
equipment.
REVENUE RECOGNITION
"Retail electric and gas" and "Wholesale energy marketing and trading"
revenues are recorded based on deliveries through the end of the calendar month.
"Energy related businesses" revenue includes revenues from PPL Global, PPL
Spectrum, Inc., and the mechanical contracting and engineering subsidiaries.
PPL Global's revenue includes dividends received from its investments accounted
for using the cost method. PPL Spectrum and the mechanical contracting and
engineering subsidiaries (which are indirect subsidiaries of PPL EnergyPlus)
record profits from construction contracts on the percentage-of-completion
method of accounting.
INCOME TAXES
The income tax provision for PPL Energy Supply is calculated in accordance
with SFAS 109, "Accounting for Income Taxes." The taxable income or loss is
included in the consolidated federal income tax return of PPL. The income tax
provision for PPL Energy Supply is calculated in accordance with an
intercompany tax sharing policy which provides that the taxable income be
calculated as if PPL Energy Supply filed a separate return.
CASH EQUIVALENTS
All highly liquid debt instruments purchased with original maturities of
three months or less are considered to be cash equivalents.
COMPREHENSIVE INCOME
Comprehensive income consists of net income and other comprehensive income,
defined as changes in Member's equity from transactions other than with the
Member. Other comprehensive income of PPL Energy Supply consists of foreign
currency translation adjustments and unrealized gains or losses on
available-for-sale securities. The accumulated other comprehensive income of
PPL Energy Supply at December 31, 2000 and 1999 was $(37) million and $(52)
million, respectively.
FOREIGN CURRENCY TRANSLATION
Assets and liabilities of international operations, where the local currency
is the functional currency, are translated at year-end exchange rates, and
related revenues and expenses are translated at average exchange rates
prevailing during the year. Adjustments resulting from translation are recorded
in other comprehensive income. The effect of translation adjustments on other
comprehensive income, net of income taxes, is disclosed in the Consolidated
Statement of Member's Equity and Comprehensive Income. Gains or losses relating
to foreign currency transactions are recognized in income currently. The
aggregate transaction gain or loss was not significant in 2000, 1999 or 1998.
PROJECT DEVELOPMENT COSTS
In accordance with the American Institute of Certified Public Accountants'
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities,"
PPL Global expenses the costs of evaluating potential
F-12
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
acquisition and development opportunities as incurred. Acquisition and
development costs are capitalized upon approval of the investment by the PPL
Global Board of Managers and the Finance Committee of PPL's Board of Directors
or, if later, the achievement of sufficient project milestones such that the
economic viability of the project is reasonably assured. The level of assurance
needed for capitalization of such costs requires that all major uncertainties
be resolved and that there is a high probability that the project will proceed
as planned, or that such costs will be recoverable through long-term
operations, a financing or a sale.
The continued capitalization of project development and acquisition costs is
subject to on-going risks related to successful completion. In the event that
PPL Global determines that a particular project is no longer viable, previously
capitalized costs are charged to expense in the period that such determination
is made.
GOODWILL AND INTANGIBLES
Goodwill is amortized on a straight-line basis over a 40-year period, except
for goodwill related to PPL Global's CEMAR acquisition, which is amortized on a
straight-line basis over a 30-year period.
The excess cost over the fair value of investments accounted for under the
equity method is amortized on a straight-line basis over a period not in excess
of 40 years. The unamortized excess cost (goodwill element) is reported in
"Investment in unconsolidated affiliates - at equity" on the Consolidated
Balance Sheet. See Note 3 for more information.
PPL Energy Supply records specifically identifiable intangibles when
specific rights, such as transmission rights, and contracts are acquired. These
intangibles are amortized on a straight-line basis over the lesser of their
contractual or estimated useful lives, ranging from 5 to 50 years.
In February 2001, the FASB issued a revised Exposure Draft, "Business
Combinations and Intangible Assets--Accounting for Goodwill." The FASB expects
to issue a final document in July 2001, becoming effective for fiscal years
beginning after December 15, 2001. If adopted as proposed, amortization of
goodwill and other acquired intangible assets with indefinite useful economic
lives will no longer occur and will be subject to the application of annual
impairment tests.
2. SEGMENT AND RELATED INFORMATION
PPL Energy Supply's reportable segments are Supply and International. The
Supply group includes the domestic energy marketing and generation functions of
PPL EnergyPlus and PPL Generation, respectively. The International group
includes PPL Global, the principal businesses of which are the acquisition and
development of both U.S. and international energy projects, and the ownership
and operation of international energy projects. The majority of PPL Global's
international investments are located in the U.K., Chile, El Salvador and
Brazil. Segments include direct charges, as well as an allocation of indirect
corporate costs, for services provided by PPL Services. These services costs
include functions such as financial, legal, human resources, and information
services.
F-13
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
Financial data for PPL Energy Supply's business segments are as follows
(millions of dollars):
2000 1999 1998
------ ------ ----
INCOME STATEMENT DATA
Revenues from external customers
Supply................................................... $2,665 $ 644 $ 78
International............................................ 456 330 47
------ ------ ----
3,121 974 125
Intersegment revenues
N/A--There are no intersegment revenues
Equity in earnings of unconsolidated affiliates
International............................................ 68 58 47
Depreciation and amortization
Supply................................................... 68 2 1
International............................................ 21 18
------ ------ ----
89 20 1
Amortization -- energy commitments
Supply................................................... (68)
Interest Income
International............................................ 14 1 1
Interest Expense
Supply................................................... 44 8 3
International............................................ 83 44 22
------ ------ ----
127 52 25
Income Taxes
Supply................................................... 141 (58) (2)
International............................................ (16) 29 (4)
------ ------ ----
125 (29) (6)
Net Income
Supply................................................... 223 (72) (3)
International............................................ 19 37 15
------ ------ ----
242 (35) 12
CASH FLOW DATA
Expenditures for property, plant and equipment
Supply................................................... $ 160 $ 8 $ 1
International............................................ 120 29
------ ------ ----
280 37 1
Investment in generating assets and electric energy projects
Supply................................................... 760
International............................................ 575 306 306
------ ------ ----
$ 575 $1,066 $306
F-14
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
DECEMBER 31,
-------------
2000 1999
------ ------
BALANCE SHEET DATA
Cumulative net investment in unconsolidated affiliates -- at equity
Supply.......................................................... $ 29
International................................................... 771 $ 407
------ ------
800 407
Total assets
Supply.......................................................... 4,899 1,276
International................................................... 2,564 1,445
------ ------
$7,463 $2,721
3. INVESTMENT IN UNCONSOLIDATED AFFILIATES -- AT EQUITY
PPL Energy Supply's investment in unconsolidated affiliates accounted for
under the equity method were $800 million and $407 million at December 31, 2000
and 1999, respectively. The most significant investment was PPL Global's
investment in WPDH, which was $479 million at December 31, 2000 and $303
million at December 31, 1999. At December 31, 2000, PPL Global had a 51% equity
ownership interest in WPDH, but shared joint control with Mirant. Accordingly,
PPL Global accounts for its investment in WPDH (and other investments where it
has majority ownership but lacks voting control) under the equity method of
accounting.
Investments in unconsolidated affiliates accounted for under the equity
method, and the effective equity ownership percentages, were as follows at
December 31, 2000:
PPL Global affiliates:
Bolivian Generating Group, LLC 29.3%
Latin American Energy & Electricity Fund I, LP 16.6%
Aguaytia Energy, LLC 11.4%
WPD Holdings UK 51.0%
Hidrocentrais Reunidas, LDA 50.0%
Hidro Iberica, B. V. 50.0%
Southwest Power Partners, LLC 50.0%
Western Power Distribution Limited 51.0%
PPL Generation affiliates:
Safe Harbor Water Power Corporation 33.3%
Bangor Pacific Hydro Associates 50.0%
F-15
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
Summarized below is financial information from the financial statements of
these affiliates, as comprehended in the consolidated financial statements for
the periods noted (millions of dollars):
2000 1999
------ ------
BALANCE SHEET DATA
Current assets........ $ 396 $ 385
Noncurrent assets..... 4,904 3,213
Current liabilities... 409 361
Noncurrent liabilities 3,365 1,836
2000 1999 1998
---- ------ ------
INCOME STATEMENT DATA
Revenues (a)......... $491 $1,101 $1,176
Operating Income..... 251 203 178
Net Income (a)....... 127 419 130
- --------
(a)The decrease in revenues and net income for the year 2000 were in part
due to the sale of the supply business of WPD, formerly SWEB, in the
fourth quarter of 1999.
PPL Global received dividends from its unconsolidated affiliates accounted
for under the equity method as follows (in millions): 2000, $4; 1999, $27;
1998, $43.
4. SALES TO OTHER ELECTRIC UTILITIES
As part of the corporate realignment on July 1, 2000, PPL Electric's
contracts for sales to other electric utilities were assigned to PPL
EnergyPlus. See Note 15 for information on the corporate realignment.
PPL EnergyPlus provided JCP&L with 300,000 kilowatts of capacity and related
energy from the Pennsylvania generating units through November 2000, at which
point the agreement was terminated. PPL EnergyPlus is reselling the returning
capacity and energy through its Energy Marketing Center.
In August 1999, the FERC approved new interconnection and power supply
agreements between PPL EnergyPlus and UGI. Under the new power supply
agreement, effective August 1999, UGI purchases capacity from PPL EnergyPlus
equal to UGI's PJM capacity obligation less the capacity reserve value of UGI's
owned generation and an existing power purchase agreement. In 2000, UGI
purchased a firm block of energy in addition to the capacity. The agreement
terminated in February 2001.
PPL EnergyPlus provided BG&E with 129,000 kilowatts, or 6.6%, of PPL
Susquehanna's share of capacity and related energy from the Susquehanna
station. Sales to BG&E continued under existing agreements through May 2001, at
which point the agreements ended.
PPL Montana provides power to Montana Power under two wholesale transition
sales agreements. These agreements expire in December 2001 and June 2002. PPL
Montana supplied Montana Power with 5.1 billion kWh in 2000. See Note 18 for
additional information.
5. INCOME AND OTHER TAXES
For 2000, 1999 and 1998 the statutory corporate federal income tax rate was
35%. The statutory corporate net income tax rates for Pennsylvania and Montana
were 9.99% and 6.75%, respectively.
F-16
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
The tax effects of significant temporary differences comprising PPL Energy
Supply's net deferred income tax asset were as follows (millions of dollars):
2000 1999
---- ----
DEFERRED TAX ASSETS
Deferred investment tax credits................................. $ 52
Non-utility generation contracts over market price and buybacks. 318 $38
Accrued pension costs........................................... 34 5
Deferred foreign income taxes................................... 59
Other........................................................... 83 24
Valuation allowance............................................. (8) (3)
---- ---
538 64
---- ---
DEFERRED TAX LIABILITIES
Electric utility plant--net..................................... 333 9
Foreign investments............................................. 15 19
Deferred foreign income taxes................................... 52 15
Other........................................................... 4 4
---- ---
404 47
---- ---
Net deferred tax asset............................................. $134 $17
==== ===
F-17
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
Details of the components of income tax expense, a reconciliation of federal
income taxes derived from statutory tax rates applied to income from continuing
operations for accounting purposes, and details of taxes other than income are
as follows (millions of dollars):
2000 1999 1998
----- ------ ------
INCOME TAX EXPENSE
Current--Federal..................................................... $ 109 $ (46) $ (7)
--State......................................................... 24 (19)
--Foreign....................................................... 11 10
----- ------ ------
144 (55) (7)
Deferred--Federal.................................................... (10) 25 1
--State........................................................ 1 1
--Foreign...................................................... (4)
----- ------ ------
(13) 26 1
----- ------ ------
Investment tax credit, net--Federal..................................... (6)
----- ------ ------
$ 125 $ (29) $ (6)
===== ====== ======
Total income tax expense--Federal....................................... $ 93 $ (21) $ (6)
--State............................................... 25 (18)
--Foreign............................................. 7 10
----- ------ ------
$ 125 $ (29) $ (6)
===== ====== ======
RECONCILIATION OF INCOME TAX EXPENSE
Indicated federal income tax on pre-tax income before
extraordinary item at statutory tax rate--35%...................... $ 130 $ (17) $ 2
Increase/(decrease) due to:
State income taxes................................................... 16 (12)
Amortization of investment tax credit................................ (4)
Difference related to income recognition of
foreign affiliates.................................................. (14) (13)
Foreign income taxes................................................. 7 6
Federal income tax credits........................................... (6)
Other................................................................ (4) (6) 5
----- ------ ------
(5) (12) (8)
----- ------ ------
Total income tax expense................................................ $ 125 $ (29) $ (6)
===== ====== ======
Effective income tax rate............................................... 33.6% (58.8)% (87.4)%
TAXES OTHER THAN INCOME
State gross receipts................................................. $ 24 $ 18
State capital stock.................................................. 10
Social security and other............................................ 19 1
----- ------
$ 53 $ 19
===== ======
PPL Global does not pay or record U.S. income taxes on the undistributed
earnings of its foreign subsidiaries and its 20% to 50% owned corporate joint
ventures where management has determined that the
F-18
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
earnings are permanently reinvested in the companies that produced them. The
cumulative undistributed earnings are included in consolidated Member's equity
on the Consolidated Balance Sheet. The amounts considered permanently
reinvested at December 31, 2000 and 1999 were $27 million and $20 million,
respectively. It is not practical to estimate the amount of taxes that might be
payable on these foreign earnings if they were remitted to PPL Global.
6. NUCLEAR DECOMMISSIONING COSTS
The cost to decommission the Susquehanna station is based on a site-specific
study to dismantle and decommission each unit immediately following final
shutdown. PPL Energy Supply's 90% share of the total estimated cost of
decommissioning the Susquehanna station was approximately $724 million in 1993
dollars. The estimate includes decommissioning the radiological portions of the
station and the cost of removal of non-radiological structures and materials.
The operating licenses for Units 1 and 2 expire in 2022 and 2024, respectively.
Decommissioning costs are recorded as a component of depreciation expense.
Beginning in January 1999, in accordance with the Final Order of the PUC, $130
million of decommissioning costs will be recovered from customers through the
CTC over the 11-year life of the CTC rather than the remaining life of
Susquehanna. The recovery will include a return on unamortized decommissioning
costs. Decommissioning charges were $13 million for the six months ended
December 31, 2000. Under power purchase agreements between PPL Electric and PPL
EnergyPlus, these recoveries are passed on to PPL EnergyPlus. Similarly, these
recoveries are passed on by PPL EnergyPlus to PPL Susquehanna.
Amounts collected from PPL Electric's customers for decommissioning, less
applicable taxes, are deposited in external trust funds for investment and can
only be used for future decommissioning costs. Accrued nuclear decommissioning
costs were $280 million at December 31, 2000.
In February 2000, the FASB issued a revised Exposure Draft, "Accounting for
Obligations Associated with the Retirement of Long-Lived Assets." The FASB
expects to issue a final document during the second quarter of 2001. As a
result, current industry accounting practices for decommissioning may change,
including the possibility that the estimated cost for decommissioning could be
recorded as a liability at the present value of the estimated future cash
outflows that will be required to satisfy those obligations.
7. FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments on the Consolidated Balance
Sheet approximated the estimated fair value at December 31, 2000 and 1999.
The carrying values of the nuclear plant decommissioning trust fund, other
investments, cash and cash equivalents, other financial instruments included in
other current assets, and commercial paper and bank loans generally are based
on established market prices and approximate fair value. The fair value of
long-term debt generally is based on quoted market prices for the securities
where available, and on estimates based on current rates offered to PPL Energy
Supply where quoted market prices are not available.
8. CREDIT ARRANGEMENTS AND FINANCING ACTIVITIES
Financing for PPL Energy Supply's investment and working capital needs was
obtained primarily from affiliates of PPL. Financing for PPL Global's foreign
operations is generally obtained in the local currencies and
F-19
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
from local lenders. Short-term borrowings outstanding were $2,290 and $1,241
million at December 31, 2000 and 1999, respectively. Of this amount, borrowings
from other PPL affiliates were $2,120 and $863 million at December 31, 2000 and
1999, respectively. This debt was payable on demand at an average interest rate
of 7.3% and 6.8% at December 31, 2000 and 1999, respectively. The remaining
balance of $170 million at December 31, 2000 is short-term bank debt of foreign
affiliates, at an average interest rate of 9.2%. The remaining balance of $378
million at December 31, 1999 is comprised of $370 million of debt related to
PPL Montana and $8 million of short-term bank debt of foreign affiliates, at an
average interest rate of 8.5%.
Long-term debt, including the current portion at December 31, 2000 and 1999
consists of the following:
OUTSTANDING
----------
2000 1999 MATURITY
---- ---- ---------
18% Banco Rural S.A.--Brazilian real denominated $ 25 2002
5%-10% Electrobras--Brazilian real denominated.. 98 2012
13% Electronorte S.A.--U.S. dollar denominated.. 19 2005
6%-8% Brazilian Govt.--U.S. dollar denominated.. 4 2014-2024
LIBOR Brazilian Govt.--U.S. dollar denominated.. 6 2001-2024
6% Bolivian Govt................................ 11 2001-2013
5.9%-7.2% UF denominated debt with various banks 15 $38 2000-2014
9% Note payable................................. 10 2002-2005
Other........................................... 4 2001-2018
---- ---
192 38
Less amount due within one year................. (33) (5)
---- ---
Total long-term debt......................... $159 $33
==== ===
The effective interest rate on long-term debt, including the current
portion, was 10.4% and 7.1% at December 31, 2000 and 1999, respectively.
Future principal repayments on long-term debt as of December 31, 2000 are as
follows (in millions):
2001...... $33
2002...... 54
2003...... 29
2004...... 32
after 2004 44
----
$192
====
In 1999, PPL Montana entered into $950 million of credit facilities with a
group of banks, including a $675 million 364-day facility and two revolving
credit facilities totaling $275 million which mature in 2002. The purpose of
these facilities was to provide bridge loan financing for the acquisition of
the Montana assets and to fund PPL Montana's working capital needs. As noted
above, PPL Montana had $370 million of borrowings outstanding under these
facilities at December 31, 1999.
In July 2000, PPL Montana completed the sale of its investment in the
Colstrip coal-fired plant to owner lessors, which are leasing the assets back
to PPL Montana under four 36-year operating leases. The proceeds
F-20
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
from the sale were approximately $410 million. PPL Montana used these proceeds
to reduce outstanding debt and make distributions to its parent, PPL
Generation. This sale-leaseback was financed with the private issuance of
pass-through certificates due in 2020. In March 2001, the private securities
were exchanged for registered securities under an S-4 registration statement
filed with the SEC. During 2000, PPL Montana reduced the amount of the credit
facilities to $100 million. At December 31, 2000, no borrowings were
outstanding under these facilities. PPL Montana has also obtained letters of
credit in the aggregate amount of $71 million.
Subsequent to the end of 2000, PPL Montana entered into a new credit
facility to allow for incremental letter of credit capacity of $150 million.
PPL Montana then issued $145 million letters of credit under this new facility
to replace the outstanding letters of credit issued on its behalf by PPL
Capital Funding. As of June 2001, there are no outstanding letters of credit
for PPL Montana.
In September 2000, a PPL Global subsidiary entered into an agreement with a
lessor to lease turbine-generators and related equipment. See Note 9 for
additional information.
9. ACQUISITIONS, DEVELOPMENT AND DIVESTITURES
DOMESTIC GENERATION PROJECTS
In 1998, PPL Global signed definitive agreements with Montana Power,
Portland General Electric Company (Portland) and Puget Sound Energy, Inc.
(Puget) to acquire interests in 13 Montana power plants, with 2,372 gross
megawatts of generating capacity, for a purchase price of $1.546 billion. The
acquisition involved the Colstrip and Corette coal-fired plants, 11
hydroelectric facilities and a storage reservoir. The Puget and Portland
agreements also provided for the acquisition of related transmission assets for
an additional $126 million, subject to certain conditions. In December 1999,
PPL Global completed the purchase of about 1,315 gross megawatts of generating
assets from Montana Power for approximately $759 million. This acquisition
transferred to PPL Montana the 11 hydroelectric facilities, the storage
reservoir, the Corette plant and Montana Power's ownership interest in three of
the four units of the Colstrip plant, along with other generation-related
assets. This acquisition was financed with a contribution of $394 million from
the Member, with the balance from short-term debt. In addition, the Member
contributed $23 million of property, equipment, financing and acquisition costs.
PPL Global's acquisition of the Colstrip interests of Puget and Portland,
totaling 1,057 additional megawatts, was subject to several conditions,
primarily the receipt by Puget and Portland of satisfactory regulatory
approvals from the state utility commissions in Washington and Oregon. However,
these satisfactory regulatory approvals were not obtained. The acquisition
agreements permitted each party to terminate the respective agreements if
closing did not occur by April 30, 2000. Both of these acquisition agreements
have now been terminated.
The Montana Power Asset Purchase Agreement, which PPL Global assigned to PPL
Montana, provided that if neither the Puget nor the Portland acquisitions were
consummated, PPL Montana would be required to purchase a portion of Montana
Power's interest in the 500-kilovolt Colstrip Transmission System for $97
million, subject to receipt of required regulatory approvals, which have been
received. PPL Montana is currently in discussions with Montana Power to pursue
alternatives to acquiring this entire interest in the Colstrip Transmission
System as contemplated by the asset purchase agreement. These discussions are
ongoing; therefore PPL Montana cannot predict whether it will buy all, or less
than all, of Montana Power's entire interest in the Colstrip Transmission
System, or what the purchase price will be if a purchase occurs.
In May 1999, PPL Global acquired most of Bangor Hydro's generating assets
and certain transmission rights, as well as its interest in an oil-fired
generating facility, for $79 million. In August 1999, PPL Global
F-21
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
purchased Bangor Hydro's 50% interest in the 20-megawatt West Enfield Hydro
Electric station for $10 million. Ownership of these Maine assets was
transferred to a PPL Generation subsidiary in the corporate realignment. See
Note 15 for more information.
In July 1999, PPL Global reached an agreement with Duke Energy North America
LLC (Duke) to jointly complete the Griffith Energy Project, a gas-fired,
combined-cycle power plant near Kingman, Arizona. As part of the agreement, PPL
Global transferred a 50% interest in the project to Duke. PPL Global will fund
50% of the project. The facility, expected to be in service in mid-2001, will
have a nominal base-load capacity of 500 megawatts and a peak capacity of 600
megawatts, at a total cost estimated at about $300 million.
In May 2000, PPL Global announced plans to install five compact, natural
gas-fired electric generation facilities in eastern Pennsylvania totaling about
900 megawatts of capacity. The five facilities, with an estimated total cost
between $450 and $500 million, will be peaking generators to be used during
periods of high energy demand. These facilities are expected to be completed by
the summer of 2003, pending necessary governmental approvals.
PPL Global continues to pursue plans to build distributed generation in New
York state. The current emphasis is on a facility for 300 megawatts of capacity
at a total capital cost of approximately $200 million.
In August 2000, PPL Global announced that construction had begun on a 225
megawatt natural gas-fired turbine facility in Wallingford, CT. The facility,
at an estimated cost of $155 million, is expected to be operational in the
third quarter of 2001.
In September 2000, a PPL Global subsidiary entered into an arrangement that
provides 30 turbine-generators for PPL Energy Supply's domestic expansion
program. The gas-fired, 50 megawatt turbine-generators and related equipment,
manufactured by General Electric, will provide PPL Energy Supply with
flexibility in growing its electricity generation and marketing business in
various regions of the U.S. General Electric will receive approximately $400
million under the terms of the arrangement. The turbines are being financed
using a leasing structure, with the PPL Global subsidiary as the lessee, which
eliminates the need for any cash outlays during the turbine manufacturing
process and diversifies PPL Energy Supply's funding sources. The units are
expected to go into service beginning in 2002. The arrangement also gives the
lessor the option to purchase an additional 36 turbine-generators and lease
them to the PPL Global subsidiary. See Note 18 for additional information. In
May 2001, a PPL Global subsidiary exercised its option on 12 of the additional
turbine-generators.
In December 2000, PPL Global announced plans to develop a gas-fired plant in
Pinal County, Arizona that will operate during times of intermediate and high
demand for electricity. The facility will use combustion turbines that PPL
Energy Supply recently acquired from General Electric (described above). The
facility is expected to be in operation by summer 2002, pending necessary
governmental approvals. The current emphasis is on a facility for 500 to 600
megawatts of capacity with an anticipated project cost of about $300 million.
In December 2000, PPL Global signed an agreement to purchase Starbuck Power
Company, LLC from Northwest Power Enterprises, Inc. which will transfer the
ownership and development rights for an up to 1,200 megawatt gas-fired,
combined cycle power plant to be built in eastern Washington state. The
facility, to be called PPL Starbuck, is expected to be in service by 2004,
pending necessary governmental approvals. The expected cost of the facility is
approximately $600 million.
F-22
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
In January 2001, PPL Montour acquired an additional interest in the
coal-fired Conemaugh Power Plant from Potomac Electric Power Company. Under the
terms of the acquisition agreement, PPL Montour and a subsidiary of Allegheny
Energy Inc. jointly acquired a 9.72% interest in the 1,711 megawatt plant. PPL
Montour paid $78 million for this additional 83 megawatt interest in the plant.
The purchase increased PPL Montour's ownership interest to 16.25% in the
two-unit plant.
Development activities continue on the Lower Mount Bethel project, a 600
megawatt combined cycle facility plant in Lower Mount Bethel, PA. The facility,
at an estimated cost of $400-$450 million, is expected to be in service in late
2003 or early 2004, pending necessary governmental approvals.
INTERNATIONAL DISTRIBUTION PROJECTS
In July 1999, PPL Global acquired an additional 29.4% interest in Emel,
resulting in majority ownership and control. In August, October and November
1999, PPL Global acquired a 29.5% additional ownership in Emel, and four of
Emel's subsidiaries. As a result, PPL Global's ownership of Emel is 95.4%, and
PPL Global also had a majority interest in EC, a holding company jointly owned
at that time by PPL Global and Emel. As a result, PPL Global consolidated the
financial statements of Emel and EC effective January 1, 1999.
In September 1999, a subsidiary of PPL Global's U.K. affiliate, WPDH, sold
its electricity supply business to London Electricity for about $264 million.
PPL Global recorded an after tax gain from the sale of $64 million. The
electric supply business provided about 15% of WPDH's annual earnings. PPL
Global and Mirant continue joint ownership of the electric delivery business,
which has been renamed WPD. WPD continues to own and operate an extensive power
network in southwest Britain, transporting and delivering electricity to 1.4
million customers.
In December 1999, the U.K.'s Office of Gas and Electricity Markets, the
regulatory authority for electricity and natural gas distribution, announced
the final price review for the electric distribution companies, including WPD.
In this final price review, WPD was given a one-time rate cut of 19%, the
lowest rate reduction among distribution companies in the U.K. The price cut is
effective for five years starting in April 2000. As a result of this action,
PPL Global evaluated the carrying value of its investment in WPD and the
investment was written down by approximately $36 million. In December 1999, in
unrelated transactions, PPL Global wrote down the carrying value of two other
international investments by a total of about $16 million.
At the end of June 2000, PPL Global finalized the acquisition of an 84.7%
interest in CEMAR, an electricity distribution company in Brazil. The
acquisition price was $289 million, financed initially with short-term debt.
In August 2000, WPDL submitted an offer to purchase shares of Hyder for 365
pence per share, or a total purchase price of 559 million British pounds
sterling ($838 million based on current exchange rates at that time). Hyder is
the owner of South Wales Electricity plc, an electric distribution company
serving approximately 980,000 customers in southern Wales. Hyder also owns
Welsh Water and certain other service-oriented businesses.
On September 15, 2000, WPDL's offer of 365 pence per share was declared
unconditional in all respects and remained open for acceptance by Hyder
shareowners through October 25, 2000. Designation of the increased offer as
unconditional allowed WPDL to take operational control of Hyder.
On September 29, 2000, WPDL closed on the purchase of approximately 110
million shares of Hyder for a total purchase price of about 395 million British
pounds sterling ($584 million based on current exchange rates at
F-23
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
that time). When combined with WPDL's existing ownership interest in Hyder,
this purchase gave WPDL approximately 70% of Hyder's total outstanding shares.
Subsequently, WPDL purchased the remaining shares of Hyder.
PPL Global's ownership interest in WPDL is 51%, but it has joint control
with Mirant, whose ownership interest is 49%. PPL Global's share of the
acquisition cost was made from existing resources and facilities, of which
approximately $100 million is expected to be repaid during the second quarter
of 2001. Based on a 51% ownership interest, PPL Global's share of the total
investment in WPDL was $114 million at December 31, 2000.
At December 31, 2000, WPDL was actively pursuing a range of options with
respect to Hyder's non-electric businesses. In this regard, WPDL offered a
contract for the management of Hyder's water business in a competitive bid
process, pursuant to European Union procurement rules. At the same time, WPDL
announced an agreement in principle with Welsh firm Glas Cymru Cyfyngedig
(Glas) for the disposition of the water business. See Note 18 for additional
information.
In October 2000, PPL Global announced a partnership with the Claro group, a
key shareowner of CGE, a leading energy distribution company in Chile and
Argentina. PPL Global had a 2.9% ownership interest in CGE at December 31,
2000. Under the terms of the partnership, the Claro group had the right to sell
up to an additional 5.6% to PPL Global over the next two years. In January
2001, PPL Global purchased the additional 5.6% of CGE from the Claro group,
bringing its total investment to $141 million, or 8.5%. CGE provides
electricity delivery services to 1.4 million customers in Chile, and natural
gas delivery services to 200,000 customers in Santiago.
ENERGY RELATED BUSINESSES
In 1998, PPL Energy Supply acquired H.T. Lyons, Inc. and McClure Company. In
1999, McCarl's, Inc., PPL Energy Services Northeast, Inc. and Burns Mechanical,
Inc. were acquired. In 2000, three smaller mechanical engineering and
contracting firms were acquired. The individual purchase prices of these
acquisitions were not significant.
In February 2001, a subsidiary of PPL Energy Services Northeast executed an
agreement acquiring certain service assets from mechanical contracting and
engineering subsidiaries of NiSource Inc. for an amount that was not
significant. Assets acquired include contracts in process, accounts receivable,
fixed assets and intangibles.
10. STOCK-BASED COMPENSATION
Under the PPL ICP and ICPKE (together, the Plans), restricted shares of PPL
common stock as well as stock options may be granted to officers and other key
employees of PPL and other affiliated companies, including PPL Energy Supply.
Awards under the Plans are made in the common stock of PPL by the Compensation
and Corporate Governance Committee of the Board of Directors in the case of the
ICP, and by the PPL Corporate Leadership Council in the case of the ICPKE. Each
Plan limits the number of shares available for awards to two percent of the
outstanding common stock of PPL on the first day of each calendar year. The
maximum number of options that can be awarded under each Plan to any single
eligible 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 as treasury stock by PPL or common
stock purchased on the open market (including private purchases) in accordance
with applicable securities laws.
F-24
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
RESTRICTED STOCK
Restricted shares of PPL 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 changes,
as defined by the Plans.
Restricted stock awards of 227,858, 25,100 and 13,421 shares, with per share
weighted-average fair values of $21.52, $26.77, and $22.16, were granted in
2000, 1999 and 1998, respectively. Compensation expense for these three years
was not significant.
At December 31, 2000, there were 426,989 restricted shares outstanding.
Included in this total were restricted stock awards of 117,490, 23,430 and
19,690, with per share weighted-average fair values of $21.27, $26.71, and
$22.48 granted in 2000, 1999, and 1998, respectively, to employees of
predecessors prior to the inclusion of such predecessors in PPL Energy Supply.
Restricted stock awards currently vest from three to twenty-one years from
the date of grant.
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'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 or a
subsidiary, in installments as determined by the Compensation and Corporate
Governance Committee of the Board of Directors in the case of the ICP, and the
PPL Corporate Leadership Council in the case of the ICPKE. The Committee (or
the Corporate Leadership Council, in the case of the ICPKE) has 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 changes, as
defined by the Plans. PPL does not grant Incentive Stock Options under these
Plans.
PPL Energy Supply 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 FASB 123, "Accounting for Stock-Based
Compensation," was not significant.
A summary of stock option activity related to PPL Energy Supply follows:
2000 1999
------------------------- -------------------------
WEIGHTED AVERAGE WEIGHTED AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE
------- ---------------- ------- ----------------
Outstanding at beginning of year 147,900 $26.85
Granted (a)..................... 583,330 $22.67 226,680 $26.85
Exercised....................... (28,495) $26.84
Forfeited....................... (46,980) $25.05 (78,780) $26.84
------- -------
Outstanding at December 31,..... 655,755 $23.27 147,900 $26.85
Exercisable at December 31,..... 69,463 $25.76
- --------
(a) Include amounts granted in 1999 to employees of predecessors prior to the
inclusion of such predecessors in PPL Energy Supply.
F-25
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
The weighted average fair values of options at their grant date during 2000
and 1999 were $3.32 and $2.37, respectively. The estimated fair value of each
option granted is calculated using a modified Black-Scholes option-pricing
model. The weighted average assumptions used in the model were as follows:
2000 1999
------ ------
Risk-free interest rate.. 6.72% 5.61%
Expected option term..... 10 yr. 10 yr.
Expected stock volatility 20.04% 16.19%
Dividend yield........... 5.70% 6.60%
Outstanding options had a weighted-average remaining life of 8.9 years at
December 31, 2000.
11. RETIREMENT AND POSTEMPLOYMENT BENEFITS
PENSION AND OTHER POSTRETIREMENT BENEFITS
PPL and its subsidiaries, including certain PPL Energy Supply predecessors,
sponsor various pension and other postretirement and postemployment benefit
plans.
PPL Montana sponsors a funded, noncontributory defined benefit plan covering
substantially all employees. PPL Montana, PPL Global and PPL EnergyPlus also
sponsor supplemental retirement plans that provide benefits to directors,
executives, and other key management employees through nonqualified retirement
plans.
PPL Montana also sponsors a postretirement plan to provide for certain
health care and life insurance benefits for its employees upon retirement.
Employees of other PPL Generation and PPL EnergyPlus subsidiaries are
provided similar benefits to those listed above under plans sponsored by PPL.
The disclosures that follow relate only to those plans sponsored by U.S.
subsidiaries of PPL Energy Supply.
Net pension and postretirement medical benefit costs were (millions of
dollars):
POSTRETIREMENT MEDICAL
PENSION BENEFITS BENEFITS
---------------- ----------------------
2000 1999 1998 2000 1999 1998
----- ---- ---- ---- ---- ----
Service cost........................................ $ 1.8 $ .2 $ .2 $ .2
Interest cost....................................... 2.4 .2 .2 .3
Expected return on plan assets...................... (2.2)
Net amortization and deferral....................... .3 .2
----- ---- ---- ---- - -
Net periodic pension and postretirement benefit cost $ 2.3 $0.6 $0.4 $0.5
===== ==== ==== ==== = =
Postretirement medical costs at December 31, 2000 were based on the
assumption that costs would increase 7.25% in 2000, then the rate of increase
would decline gradually to 6% in 2006 and thereafter. A one-percentage point
change in the assumed health care cost trend assumption would have an
insignificant affect on service and interest cost components, and the
postretirement obligation.
F-26
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
The following assumptions were used in the valuation of the benefit
obligations:
POSTRETIREMENT MEDICAL
PENSION BENEFITS BENEFITS
--------------- ----------------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
Discount rate................. 7.5% 7.0% 6.25% 7.5% 7.0%
Expected return on plan assets 9.2% 8.0%
Rate of compensation increase. 4.75% 5.0% 5.0%
The funded status of the combined plans was as follows (millions of dollars):
POSTRETIREMENT MEDICAL
PENSION BENEFITS BENEFITS
--------------- ----------------------
2000 1999 2000 1999
----- ------ ----- -----
Change in Benefit Obligation
Benefit Obligation, January 1................................... $34.5 $ 3.3 $ 3.5
Service cost................................................. 1.8 .2 .2
Interest cost................................................ 2.4 .2 .3
Plan amendments.............................................. .3 1.8
Actuarial (gain)/loss........................................ (2.5) (.6) .2
Acquisitions/Divestitures.................................... 29.6 $ 3.5
----- ------ ----- -----
Benefit Obligation, December 31................................. $36.5 $ 34.5 $ 4.2 $ 3.5
===== ====== ===== =====
Change in Plan Assets
Plan assets at fair value, January 1............................ $23.8
Actual return on plan assets................................. .6
Acquisitions/divestitures.................................... 3.2 $ 23.8
----- ------
Plan assets at fair value, December 31.......................... $27.6 $ 23.8
===== ======
Funded Status
Funded Status of Plan........................................... $(8.9) $(10.7) $(4.2) $(3.5)
Unrecognized prior service cost................................. 2.7 2.7
Unrecognized net loss........................................... (.4) .4 (.1)
----- ------ ----- -----
Liability recognized............................................ $(6.6) $ (7.6) $(4.3) $(3.5)
===== ====== ===== =====
Amounts recognized in the Consolidated Balance Sheet consist of:
Accrued benefit liability.................................... $(6.6) $ (7.6) $(4.3) $(3.5)
Intangible asset............................................. .1 .2
Additional minimum liability................................. (.1) (.2)
----- ------ ----- -----
Net amount recognized........................................ $(6.6) $ (7.6) $(4.3) $(3.5)
===== ====== ===== =====
The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for pension plans with accumulated benefit obligations in
excess of plan assets were (in millions) $4, $2 and $0, respectively, as of
December 31, 2000 and $5, $2 and $0, respectively, as of December 31, 1999.
PPL Energy Supply affiliates engaged in mechanical contracting and
engineering services make contributions to various union sponsored
multi-employer pension and health and welfare plans. Contributions (in
millions) of $10, $8 and $1 were made in 2000, 1999 and 1998, respectively.
F-27
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
PPL Global assumed the pension liability for employees of CEMAR in
connection with its acquisition in June 2000. CEMAR sponsors a funded
contributory defined benefit plan for its employees. At September 30, 2000 the
projected benefit obligation was $42 million offset by plan assets of $32
million, resulting in a recognized liability of $10 million.
SAVINGS PLANS
Substantially all U.S. employees of PPL Energy Supply are eligible to
participate in deferred savings plans (401(k)s). Company contributions to the
plans charged to operating expense approximated $4 million in 2000 and were
less than $1 million in 1999 and 1998 due to the timing of PPL Montana and the
other PPL Generation companies becoming predecessors of PPL Energy Supply.
12. JOINTLY OWNED FACILITIES
At December 31, 2000, PPL Energy Supply owned undivided interests in the
following facilities (millions of dollars):
ELECTRIC
UTILITY CONSTRUCTION
OWNERSHIP PLANT IN OTHER ACCUMULATED WORK IN
INTEREST SERVICE PROPERTY DEPRECIATION PROGRESS
--------- -------- -------- ------------ ------------
PPL GENERATION
Generating Stations
Susquehanna......... 90.00% $4,187 $3,504 $21
Keystone............ 12.34% 70 45 1
Wyman............... 8.33% 15 1
Conemaugh........... 11.39%(a) 107 54
Merrill Creek Reservoir 8.37% $22 12
- --------
(a)On January 8, 2001, a PPL Generation subsidiary purchased an additional 83
megawatts of generation capacity at the Conemaugh Generating station. The
addition brings PPL Generation's ownership to 16.25%.
Each PPL Generation subsidiary, either on its own behalf or through another
PPL Energy Supply affiliate, provided its own financing for its share of the
facilities above. Each receives a portion of the total output of the generating
stations equal to its percentage ownership. The share of fuel and other
operating costs associated with the stations is reflected on the Consolidated
Statement of Income.
13. COMMITMENTS AND CONTINGENT LIABILITIES
PPL Energy Supply and its related subsidiaries are involved in numerous
legal proceedings, claims and litigation in the ordinary course of business.
PPL Energy Supply and its subsidiaries cannot predict the ultimate outcome of
such matters, or whether such matters may result in material liabilities;
however, PPL Energy Supply and its subsidiaries believe they have meritorious
defense to all such proceedings, claims and litigation.
WHOLESALE ENERGY COMMITMENTS
As part of the purchase of generation assets from Montana Power, PPL Montana
agreed to supply electricity to Montana Power under two wholesale transition
service agreements. The agreements expire in 2001 and 2002. PPL Montana also
agreed to supply electricity to another party through December 2010.
Additionally, PPL
F-28
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
Montana assumed a power purchase agreement, which expires in April 2010. In
accordance with purchase accounting requirements, PPL Montana recorded a
liability of $118 million as an estimate of the fair value of the contracts at
the acquisition date. The supply and purchase contracts are prospectively
amortized over the contract terms as adjustments to "Wholesale energy marketing
and trading" revenues and "Energy purchases," respectively. The unamortized
balances associated with these wholesale energy commitments (in millions) were
$99 and $97 at December 31, 2000 and 1999, respectively.
LIABILITY FOR ABOVE MARKET NUG CONTRACTS
At June 30, 1998, PPL Electric recorded a loss accrual for above market
contracts with NUGs of $854 million. Effective January 1999, PPL Electric began
reducing this liability as an offset to "Energy purchases" on the Consolidated
Statement of Income. This reduction is based on the estimated timing of the
purchases from the NUGs and projected market prices for this generation. The
final existing NUG contract expires in 2014. In connection with the corporate
realignment, effective July 1, 2000, the remaining balance of this liability
was transferred to PPL EnergyPlus. The liabilities associated with these above
market NUG contracts were $674 million at December 31, 2000.
COMMITMENTS--ACQUISITIONS AND DEVELOPMENT ACTIVITIES
PPL Global and its subsidiaries have committed additional capital and
extended loans to certain affiliates, joint ventures and partnerships in which
they have an interest. At December 31, 2000, PPL Global and its subsidiaries
had approximately $839 million of such commitments. The majority of these
commitments are for the purchase of turbines from General Electric, as well as
the January 2001 Conemaugh and CGE acquisitions, as discussed in Note 9.
NUCLEAR INSURANCE
PPL Susquehanna is a member of certain insurance programs that provide
coverage for property damage to members' nuclear generating stations.
Facilities at the Susquehanna station are insured against property damage
losses up to $2.75 billion under these programs. PPL Susquehanna is also a
member of an insurance program that provides insurance coverage for the cost of
replacement power during prolonged outages of nuclear units caused by certain
specified conditions. Under the property and replacement power insurance
programs, PPL Susquehanna could be assessed retroactive premiums in the event
of the insurers' adverse loss experience. At December 31, 2000, this maximum
assessment was about $20 million.
PPL Susquehanna's public liability for claims resulting from a nuclear
incident at the Susquehanna station is limited to about $9.5 billion under
provisions of The Price Anderson Amendments Act of 1988. PPL Susquehanna is
protected against this liability by a combination of commercial insurance and
an industry assessment program. In the event of a nuclear incident at any of
the reactors covered by The Price Anderson Amendments Act of 1988, PPL
Susquehanna could be assessed up to $176 million per incident, payable at $20
million per year.
ENVIRONMENTAL MATTERS
AIR
The Clean Air Act deals, in part, with acid rain, attainment of federal
ambient ozone standards and toxic air emissions. PPL Energy Supply is in
substantial compliance with the Clean Air Act.
F-29
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
The DEP has finalized regulations requiring further seasonal (May-June) NOx
reductions to 80% from 1990 levels starting in 2003. These further reductions
are based on the requirements of the Northeast Ozone Transport Region
Memorandum of Understanding and two EPA ambient ozone initiatives: the
September 1998 EPA State Implementation Plan (SIP) call (i.e., EPA's
requirement for states to revise their SIPs) issued under Section 110 of the
Clean Air Act, requiring reductions from 22 eastern states, including
Pennsylvania; and the EPA's approval of petitions filed by Northeastern states,
requiring reductions from sources in 12 Northeastern states and Washington,
D.C., including sources of PPL Energy Supply. The EPA's SIP-call was
substantially upheld by the D.C. Circuit Court of Appeals in an appeals
proceeding.
Although the Court extended the implementation deadline to May 2004, the DEP
has not changed its rules accordingly. PPL Energy Supply expects to achieve the
2003 NOx reductions with the recent installation of SCR technology on the
Montour units and possibly SCR or SNCR on a Brunner Island unit.
The EPA has also developed new standards for ambient levels of ozone and
fine particulates. These standards were challenged and remanded to the EPA by
the D.C. Circuit Court of Appeals in 1999. However, on appeal to the United
States Supreme Court, the D.C. Circuit Court's decision was reversed in part
and remanded to the D.C. Circuit Court. The new particulates standard, if
finalized, may require further reductions in SO2 for certain PPL Energy Supply
facilities and year-round NOx reductions commencing in 2010-2012 at SIP-call
levels in Pennsylvania, and at slightly less stringent levels in Montana. The
revised ozone standard, if finalized, is not expected to have a material effect
on facilities of PPL Energy Supply.
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 emissions should be regulated and has determined that mercury
emissions must be regulated. EPA is expected to develop regulations by 2004.
In 1999, the EPA initiated enforcement actions against several 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. At this time,
PPL Energy Supply is unable to predict whether such EPA enforcement actions
will be brought with respect to any of its affiliates' plants. However, the EPA
regional offices that regulate plants in Pennsylvania (Region III) and Montana
(Region VIII) have indicated an intention to issue information requests to all
utilities in their jurisdictions and the Region VIII Office has issued such a
request to PPL Montana's Corette plant. PPL Energy Supply cannot at present
predict what, if any, action EPA may take following responses by its affiliates
to such information requests. Should EPA commence one or more enforcement
actions against affiliates of PPL Energy Supply, compliance with any EPA
enforcement actions could result in additional capital and operating expenses
in amounts which are not now determinable, but which could be significant.
The EPA has put on hold its proposed revisions to its regulations that would
have required power plants to meet "New Source" performance standards and/or
undergo "New Source" review for many maintenance and repair activities that are
currently exempted.
WATER/WASTE
The final National Pollutant Discharge Elimination System permit for the
Montour plant contains stringent limits for iron discharges. The results of a
toxic reduction study show that additional water treatment facilities or
operational changes are needed at this station. A plan for these changes is
being developed and will be submitted to DEP in the fall of 2001.
F-30
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
The EPA significantly tightened the water quality standard for arsenic in
2000. However, the EPA has now withdrawn the standard in order to further study
the matter. A tightened standard may require PPL Energy Supply to further treat
wastewater and/or take abatement action at several of its power plants, the
cost of which is not now determinable, but could be significant.
Capital expenditures from 2001 to 2005 to correct groundwater degradation at
fossil-fueled generating stations, and to address waste water control at
facilities of PPL Energy Supply, are expected to approximate $217 million.
Additional capital expenditures could be required beyond the year 2005 in
amounts which are not now determinable but which could be material. Actions
taken to correct groundwater degradation, to comply with the environmental
regulations and to address waste water control, are also expected to result in
increased operating costs in amounts which are not now determinable but which
could be significant.
EPA's proposed requirements for new or modified intake structures will
affect where generating facilities are built, will establish intake design
standards, and could lead to requirements for cooling towers at new power
plants. These proposed regulations are expected to be finalized by August 2001.
In the worst case, the rule could require new or modified cooling towers at one
or more stations of PPL Energy Supply. Another new rule, also expected in 2001,
will address existing structures. Each of these rules could impose significant
costs on PPL Energy Supply, which are not now determinable.
OTHER REMEDIATION
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 PPL Montana of any such changes in laws or
regulations or any such increase in citizen suits is not currently
determinable, but could be significant.
Oil or other contamination from past spills and releases that may exist at
facilities owned by PPL Energy Supply, is being addressed under a consent order
with the DEP. Future cleanup or remediation work at sites currently under
review, or at sites not currently identified, may result in material additional
operating costs for PPL Energy Supply that cannot be estimated at this time.
Under the Montana Power acquisition agreement, PPL Montana is indemnified by
Montana Power for any pre-acquisition environmental liabilities. However, this
indemnification is conditioned on certain circumstances that can result in PPL
Montana and Montana Power sharing in certain costs within limits set forth in
the agreement.
GENERAL
Due to the environmental issues discussed above or others, PPL Energy Supply
may be required to modify, replace or cease operating certain facilities to
comply with statutes, regulations and actions by regulatory bodies or courts.
In this regard, PPL Energy Supply also may incur capital expenditures,
operating expenses and other costs in amounts which are not now determinable,
but which could be significant.
CREDIT SUPPORT FOR AFFILIATED COMPANIES
PPL provides certain guarantees for PPL Energy Supply. As of December 31,
2000, PPL had guaranteed certain obligations of PPL EnergyPlus for up to $625
million under power purchase and sales agreements. PPL had also guaranteed
certain obligations of PPL Energy Supply, totaling $103 million at December 31,
2000.
F-31
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
SOURCE OF LABOR SUPPLY
At December 31, 2000, PPL Energy Supply, though its predecessors, had
approximately 7,196 full-time employees. This included 2,398 in PPL Generation,
1,697 in PPL EnergyPlus, 45 in PPL Global, and 3,056 in several Central and
South American electric companies controlled by PPL Global.
Approximately 31%, or 1,298 employees, of PPL Energy Supply's domestic
workforce are members of labor unions, with three IBEW locals, representing
nearly 1,290. The bargaining agreement with the largest union was negotiated in
1998 and expires in May of 2002. Three agreements will expire during 2001, for
three locals representing about 320 employees in Montana. In June 2001, a
tentative agreement was reached with the union representing PPL Montana's
Colstrip plant union employees.
14. RELATED PARTY TRANSACTIONS
A wholly-owned subsidiary of PPL Global extended a 90 million British pounds
sterling loan facility to WPDH. This facility was subsequently reduced to 76.5
million British pounds sterling. This facility provided funds that were loaned
to WPDL as temporary financing for the acquisition of Hyder. The facility was
entered into September 28, 2000, and expires September 25, 2001. Interest is
reset monthly based on sterling LIBOR. This rate was 6.4% as of December 31,
2000. At December 31, 2000, WPDH had borrowed 76.5 million British pounds
sterling (US $114 million at the foreign exchange rate on December 31, 2000.)
WPDH repaid this loan in May 2001.
At December 31, 2000, PPL Global had a $135 million note payable to an
affiliate of WPDH. The note was denominated in U.S. dollars, and provided for
interest at market rates. PPL Global repaid this note in January, 2001.
PPL and PPL Capital Funding provide funding for PPL Energy Supply. Such
funding includes loans that are due on demand and interest is charged at a rate
based on PPL Capital Funding's short-term borrowing rate. In addition, PPL
Energy Supply has notes receivable from other affiliates of PPL. These notes
were issued in conjunction with PPL's overall cash management strategies.
Interest earned on loans to affiliated companies and interest incurred on
borrowings from affiliated companies are included in "Other income--net" and
"Interest expense", respectively, in the Consolidated Statement of Income.
Intercompany interest income was $13 million in 2000. Intercompany interest
expense was $86, $37 and $23 million in 2000, 1999 and 1998, respectively.
Notes receivable from affiliated companies and short-term debt payable to
affiliated companies at December 31, 2000 were (in millions) $1,279 and $2,120,
respectively. These amounts include receivables from, and payables to, WPDH and
its affiliates, as discussed above.
As part of the corporate realignment, PPL Electric entered into power sales
agreements with PPL EnergyPlus for the purchase of electricity to meet its
obligations as a PLR for customers who have not selected an alternative
supplier under the Customer Choice Act. Under the terms of these agreements,
this electricity is purchased by PPL Electric at the applicable shopping
credits authorized by the PUC, plus nuclear decommissioning costs, less state
taxes. These sales totaled $540 million for the six months ended December 31,
2000, and are included in "Wholesale energy marketing and trading" on the
Consolidated Statement of Income.
Also as part of the corporate realignment (see Note 15), PPL Electric
executed a reciprocal contract with PPL EnergyPlus to sell electricity
purchased under contracts with NUGs. PPL Electric purchases electricity from
the NUGs at contractual rates, and then sells the electricity at the same price
to PPL EnergyPlus. These expenses
F-32
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
totaled $85 million for the six months ended December 31, 2000, and are
included in "Energy purchases" on the Consolidated Statement of Income.
Corporate functions such as financial, legal, human resources and
information services were transferred to PPL Services in the corporate
realignment. PPL Services bills the respective PPL subsidiaries for the cost of
such services when the costs can be specifically identified. The cost of these
services that are not directly charged to PPL subsidiaries are allocated to
certain of the subsidiaries based on the relative capital invested by PPL in
these subsidiaries. During the period July 1 to December 31, 2000, PPL Services
charged PPL Energy Supply approximately $19 million for direct expenses, and
allocated these entities approximately $14 million of overhead costs.
15. CORPORATE REALIGNMENT
On July 1, 2000, PPL and PPL Electric completed a corporate realignment in
order to effectively separate PPL Electric's regulated transmission and
distribution operations from its recently deregulated generation operations and
to better position the companies and their affiliates in the new competitive
marketplace. The realignment included PPL Electric's transfer of certain
generation and related assets, and associated liabilities, to PPL and PPL
Energy Funding at book value. PPL Energy Funding contributed certain of these
generating and unregulated marketing assets and liabilities at a net book value
of approximately $1.6 billion, to PPL Generation and PPL EnergyPlus. The
following increases (in millions) resulted from these non-cash contributions:
ASSETS
Notes receivable from affiliated companies $ 427
Unrealized energy trading gains........... 105
Nuclear plant decommissioning trust fund.. 269
Property, plant and equipment............. 1,932
Fuel, materials and supplies.............. 144
Other assets.............................. 30
------
$2,907
======
LIABILITIES AND EQUITY
Unrealized energy trading losses $ 105
Above market NUG contracts...... 723
Deferred income taxes........... 52
Other noncurrent liabilities.... 394
Other liabilities............... 45
Member's equity................. 1,588
------
$2,907
======
PPL Energy Supply was subsequently formed as a subsidiary of PPL Energy
Funding, to serve as the parent company for the competitive subsidiaries. As a
result of the corporate realignment, PPL Generation's principal business is
owning and operating U.S. generating facilities through various subsidiaries;
PPL EnergyPlus' principal business is wholesale and unregulated retail energy
marketing; and PPL Global's principal businesses are the acquisition and
development of both U.S. and international energy projects, and the ownership
and operation of international energy projects.
The corporate realignment followed receipt of various regulatory approvals,
including approvals from the Internal Revenue Service, the PUC, the FERC, and
the NRC.
F-33
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
16. ADOPTION OF SFAS 133
On January 1, 2001, PPL Energy Supply adopted SFAS 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. PPL Energy Supply, 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, on January 1,
2001, PPL Energy Supply recorded a cumulative-effect charge of $181.7 million
in the accumulated other comprehensive income component of Member's equity to
recognize at fair value all derivatives that are designated as cash flow
hedging instruments. This adjustment includes a credit of $5.8 million for
derivatives that were previously deferred on the balance sheet. A majority of
PPL Energy Supply's fixed price commodity contracts meet the definition of
derivatives under SFAS 133. PPL Energy Supply uses these contracts and other
financial derivative instruments to mitigate commodity price risk related to
the sale of electricity as well as the purchase of oil, gas and coal. Many of
these instruments have been designated as cash flow hedges of the anticipated
purchases or sales of the commodity. The most significant portion of the
cumulative-effect adjustment is attributed to forward sales contracts and
financial swaps in which PPL Energy Supply has reserved and stands ready to
deliver energy from the planned output of its wholly owned generating units. In
these cases, PPL Energy Supply will realize a margin that represents the
difference between the sales price and the average cost of generation.
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 earnings. 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. PPL Energy Supply expects to reclassify into
earnings during the next twelve months $144.7 million from the transition
adjustment that was recorded in accumulated other comprehensive income. The
cash flow hedges described above cover various periods of time from January
2001 through December 2008.
Under the terms of SFAS 133, PPL Energy Supply also recorded at fair value
certain derivative instruments that did not qualify as hedges. This resulted in
a cumulative-effect credit to earnings of $10.6 million in recognition of these
instruments.
The cumulative-effect adjustment in earnings to recognize at fair value all
derivatives that are designated as fair-value hedging instruments and the
cumulative-effect adjustment to recognize the difference between the carrying
values and fair values of related hedged liabilities were insignificant.
17. SALES TO CALIFORNIA INDEPENDENT SYSTEM OPERATOR
PPL Energy Supply, through PPL Montana, has made certain limited sales to
the California (Cal) ISO, for which it has not yet been paid. Specifically,
through January 2001, PPL Energy Supply has made approximately $18 million of
sales to the Cal ISO. A small amount of these sales were ordered by the U.S.
Secretary of Energy (Secretary) between December 14, 2000 and February 7, 2001
pursuant to emergency authority granted to the Secretary pursuant to Federal
law. The Secretary has not exercised his emergency authority after February 7,
F-34
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
2001. PPL Energy Supply negotiated prices for a portion of the involuntary
sales with the Cal ISO. The prices for the remaining ordered sales will be
established in future proceedings at the FERC.
Given the myriad of electricity supply problems presently faced by the
California electric utilities and the Cal ISO, PPL Energy Supply cannot predict
when it will receive payment for sales to the Cal ISO that have been made, or
that may be required to be made in the future, or the final amounts of such
payments. As of December 31, 2000, PPL Energy Supply has fully reserved for
possible underrecoveries of payments for these sales. PPL Energy Supply may
have to add to this reserve in future periods if it is required by the
Secretary to continue to supply the Cal ISO.
Litigation arising out of the California electric 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. Certain PPL Energy
Supply subsidiaries have intervened in the FERC proceedings in order to protect
its interests, but have not been named as defendants in any of the court
actions. PPL Energy Supply cannot predict whether any of its subsidiaries will
eventually be named in these lawsuits or other lawsuits, the outcome of any
such litigation or the ultimate impact on PPL Energy Supply of the California
electricity supply situation.
18. SUBSEQUENT EVENTS
STRATEGIC INITIATIVE
In April 2001, PPL announced a plan to confirm the structural separation of
PPL Electric from PPL and PPL's other affiliated companies, in a transaction
that leverages the electric transmission and distribution business of PPL
Electric. Upon completion of the transaction, PPL will effectively double the
amount of generating capacity it has to sell in wholesale electricity markets
while allowing PPL to retain valuable advantages related to operating both
energy supply and energy delivery businesses.
The initiative will be effected through a series of steps including:
. confirming the structural separation of PPL Electric from PPL and PPL's
other affiliated companies;
. an increase in the leverage of PPL Electric through the issuance of up
to $900 million of senior secured bonds without any expected material
impact at such issuance on PPL Electric's investment-grade credit
rating; and
. the solicitation by PPL Electric, in early June 2001, of bids to
contract with energy suppliers to meet all of the electricity needs
associated with its obligation to serve customers under capped rates
through the end of 2009.
PPL Electric currently has a full requirements supply agreement with PPL
EnergyPlus that expires at the end of 2001. Under the Pennsylvania Customer
Choice Act, PPL Electric is required, through 2009, to provide electricity at
pre-set prices to its delivery customers who do not select an alternate
supplier. As part of the initiative, PPL Electric solicited bids to contract
with energy suppliers to meet its obligation to deliver energy to its customers.
In June 2001, PPL Electric announced that PPL EnergyPlus was the low bidder,
among six bids examined, and was selected as the company to provide for the
energy supply requirements of PPL Electric from 2002
F-35
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
through 2009. PPL Electric has filed the contract with the PUC and the FERC,
and has requested approvals by the middle of July 2001. Under this contract,
PPL EnergyPlus would provide electricity at pre-established capped prices and
receive a $90 million payment by January 1, 2002, to offset differences between
the revenues expected under the capped prices and projected market prices
through the life of the supply agreement. The contract would result in PPL
EnergyPlus having an eight-year contract at market prices. Under its existing
contract with PPL Electric, which expires at the end of 2001, PPL EnergyPlus
provides all of PPL Electric's supply needs at the price cap level, regardless
of the prevailing market price.
TURBINE LEASE FINANCING
As described in Note 9, in September 2000 a PPL Global subsidiary entered
into a $550 million leasing arrangement with a lessor to lease
turbine-generators and related equipment. The turbines are being financed using
a leasing structure that eliminates the need for cash outlays during the
turbine manufacturing process and diversifies PPL's funding sources. In May
2001, another PPL Global subsidiary entered into an agreement, initially for
$900 million, to be increased to $1.2 billion upon syndication, for a financing
lease structure for the acquisition, development and construction of several
commercial power generation facilities. Certain obligations of the PPL Global
subsidiary under this financing have been guaranteed by PPL Energy Supply.
Closing on the syndication is anticipated in the third quarter of 2001.
PPL MONTANA'S SUPPLY TO MONTANA POWER
PPL Montana has two transition agreements to supply wholesale electricity to
Montana Power. One agreement provides for the sale of 200 megawatts from the
leasehold interest in Colstrip Unit 3 until December 2001. The second agreement
covers Montana Power until its remaining load is zero, but in no event later
than June 2002. In April 2001, PPL announced that PPL EnergyPlus has offered to
provide Montana Power with 500 megawatts of energy to be supplied by PPL
Montana. The delivery term of this new contract would be for five years
beginning July 1, 2002, which is the day after the termination date of the
second contract, pursuant to which PPL Montana supplies energy to Montana Power
to serve its retail load not served by other providers or provided by Montana
Power's remaining generation.
Under the new contract, PPL Montana would be obligated to sell this energy
to Montana Power only to the extent that the energy is produced by certain
designated units of PPL Montana. The price under the contract would be fixed at
4 cents per kWh. However, if PPL Montana is subjected to significantly
increased costs or regulatory burdens by the Montana Public Service Commission
or the Montana Legislature or any other governmental authority during the
contract period, PPL Montana could pass the resulting costs through to Montana
Power as an addition to the contract price. Also, in that event PPL Montana
could terminate the contract. After PPL EnergyPlus and Montana Power prepare
and agree to a contract, it will be submitted to the Montana Public Service
Commission and the FERC for review and approval. At this time, PPL Energy
Supply and PPL Montana cannot predict if the parties will reach an agreement,
whether any such agreement will be approved by the Montana Public Service
Commission or the FERC on acceptable terms, what actions the Montana Public
Service Commission, the Montana Legislature or any other governmental authority
may take on these or related matters, or the ultimate impact on PPL Energy
Supply and PPL Montana of any of these matters.
PPL MONTANA'S SUPPLY TO MONTANA ENERGY POOL
In June 2001, PPL Montana provided a proposed agreement to supply 20
megawatts to the Montana energy pool at 3.5 cents per kilowatt-hour. PPL
Montana would supply electricity under this agreement through June 2002.
F-36
PPL ENERGY SUPPLY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 2000, 1999 AND 1998
UNIVERSITY PARK GENERATION PROJECT
In April 2001, PPL Global announced plans to develop a power plant near
University Park in Chicago, Illinois at an expected cost of $305 million. The
Illinois plant will be a 540-megawatt, simple-cycle, natural gas-fired electric
generation facility and is expected to be in service by the summer of 2002.
SALE OF HYDER'S WATER BUSINESS
As discussed in Note 9, WPDL had previously announced an agreement with the
Welsh firm Glas for the disposition of Hyder's water business, Welsh Water.
This agreement was made subject to the successful refinancing of Welsh Water.
In May 2001, $2.7 billion of Welsh Water bonds were priced and spread across 12
tranches. Subsequently, in May 2001 Welsh Water was sold to Glas.
F-37
PPL ENERGY SUPPLY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(UNAUDITED)
(MILLIONS OF DOLLARS)
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................ $ 372 $ 130
Accounts receivable (less reserve: 2001, $60; 2000, $52). 299 355
Accounts receivable from affiliated companies............ 236 128
Unbilled revenues........................................ 98 142
Notes receivable from affiliated companies............... 747 1,279
Fuel, materials and supplies--at average cost............ 222 154
Prepayments.............................................. 33 31
Unrealized derivative gains.............................. 201 79
Deferred income taxes.................................... 2 38
Other.................................................... 49 46
------- -------
2,259 2,382
------- -------
INVESTMENTS
Investments in unconsolidated affiliates--at equity...... 767 800
Investments in unconsolidated affiliates--at cost........ 119 46
Note receivable from affiliated companies................ 649
Nuclear plant decommissioning trust fund................. 258 268
Other.................................................... 8 4
------- -------
1,801 1,118
------- -------
PROPERTY, PLANT AND EQUIPMENT--NET.......................... 3,507 3,389
------- -------
OTHER NONCURRENT ASSETS
Goodwill, net............................................ 443 452
Deferred income taxes.................................... 40 59
Other.................................................... 64 63
------- -------
547 574
------- -------
$8,114 $7,463
======= =======
The accompanying notes are an integral part of these financial statements.
F-38
PPL ENERGY SUPPLY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET--(CONTINUED)
(UNAUDITED)
(MILLIONS OF DOLLARS)
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- ------------
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt.................................. $ 109 $ 170
Short-term debt payable to affiliated companies.. 2,120
Long-term debt................................... 32 33
Accounts payable................................. 279 380
Accounts payable to affiliated companies......... 99 169
Above market NUG contracts....................... 89 93
Wholesale energy commitments..................... 18 23
Taxes............................................ 158 145
Dividends........................................ 93
Unrealized derivative losses..................... 127 84
Other............................................ 55 46
------ ------
966 3,356
------ ------
LONG-TERM DEBT...................................... 201 159
------ ------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Deferred income taxes and investment tax credits. 77 82
Above market NUG contracts....................... 516 581
Wholesale energy commitments..................... 65 76
Nuclear plant decommissioning.................... 273 280
Other............................................ 370 298
------ ------
1,301 1,317
COMMITMENTS AND CONTINGENT LIABILITIES..............
------ ------
MINORITY INTEREST................................... 52 54
------ ------
MEMBER'S EQUITY..................................... 5,594 2,577
------ ------
$8,114 $7,463
====== ======
The accompanying notes are an integral part of these financial statements.
F-39
PPL ENERGY SUPPLY, LLC
CONDENSED CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
(MILLIONS OF DOLLARS)
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- -------------------------
2001 2000 2001 2000
------ ------ ------ ------
OPERATING REVENUES
Wholesale energy marketing and trading.. $ 799 $ 889 $2,327 $1,051
Retail electric and gas................. 169 199 624 631
Energy related businesses............... 138 80 380 241
Equity in earnings of unconsolidated
affiliates............................ 27 12 89 49
------ ------ ------ ------
1,133 1,180 3,420 1,972
------ ------ ------ ------
OPERATING EXPENSES
Operation
Fuel................................ 128 129 373 145
Energy purchases.................... 387 513 1,185 983
Other operation and maintenance..... 188 169 577 241
Transmission........................ 6 9 40 38
Depreciation and amortization........... 40 31 118 50
Taxes, other than income................ 10 18 34 39
Project development..................... 1 3 13 12
Energy related businesses............... 127 84 355 223
------ ------ ------ ------
887 956 2,695 1,731
------ ------ ------ ------
OPERATING INCOME........................... 246 224 725 241
Other Income--net.......................... 25 6 53 22
------ ------ ------ ------
INCOME BEFORE INTEREST EXPENSE, INCOME
TAXES AND MINORITY INTEREST.............. 271 230 778 263
Interest Expense........................... 7 31 35 86
------ ------ ------ ------
INCOME BEFORE INCOME TAXES AND MINORITY
INTEREST................................. 264 199 743 177
Income Taxes............................... 98 73 249 53
Minority Interest.......................... 1 3 4 4
------ ------ ------ ------
NET INCOME................................. $ 165 $ 123 $ 490 $ 120
====== ====== ====== ======
The accompanying notes are an integral part of these financial statements.
F-40
PPL ENERGY SUPPLY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
(MILLIONS OF DOLLARS)
FOR THE NINE
MONTHS ENDED
SEPTEMBER 30,
---------------
2001 2000
------- ------
NET CASH PROVIDED BY OPERATING ACTIVITIES........................... $ 354 $ 231
------- ------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment................... (299) (122)
Investment in generating assets and electric energy projects..... (204) (615)
Net increase in notes receivable from affiliates................. (15) (47)
Proceeds from Montana sale-leaseback............................. 410
Other investing activities--net.................................. (3) (32)
------- ------
Net cash used in investing activities............................... (521) (406)
------- ------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt....................................... 98
Retirement of long-term debt..................................... (3) (8)
Distributions to Member.......................................... (333) (149)
Net decrease in short-term debt.................................. (50) (350)
Net increase (decrease) in short-term debt payable to affiliates. (1,200) 561
Contributions from Member........................................ 1,897 116
------- ------
Net cash provided by financing activities........................... 409 170
------- ------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................ 242 (5)
Cash and Cash Equivalents at Beginning of Period................. 130 82
------- ------
Cash and Cash Equivalents at End of Period....................... $ 372 $ 77
======= ======
NON-CASH CONTRIBUTIONS FROM MEMBER:
Intercompany notes and accounts receivable....................... $ 920
Net assets transferred in corporate realignment.................. $1,588
The accompanying notes are an integral part of these financial statements.
F-41
PPL ENERGY SUPPLY, LLC
CONDENSED CONSOLIDATED STATEMENT OF MEMBER'S EQUITY AND
COMPREHENSIVE INCOME
(UNAUDITED)
(MILLIONS OF DOLLARS)
FOR THE THREE MONTHS FOR THE NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ------------------
2001 2000 2001 2000
------ ------ ------ ------
Member's equity--beginning of period............................ $5,118 $ 924 $2,577 $ 922
Member's contributions....................................... 331 1,626 2,817 1,639
Net income................................................... 165 123 490 120
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments................. (12) 10 (83) 2
Unrealized gain on qualifying derivatives................ 33
Distributions to Member...................................... (8) (149) (240) (149)
------ ------ ------ ------
Member's equity--end of period.................................. $5,594 $2,534 $5,594 $2,534
------ ------ ------ ------
Statement of Comprehensive Income:
Net income................................................... $ 165 $ 123 $ 490 $ 120
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments, net of tax
(benefit) of $(26), $(3), $(39), $(10)................. (12) 10 (83) 2
Unrealized gain on qualifying derivatives,
net of tax of $21...................................... 33
------ ------ ------ ------
Total other comprehensive income (loss)...................... (12) 10 (50) 2
------ ------ ------ ------
Comprehensive income......................................... $ 153 $ 133 $ 440 $ 122
====== ====== ====== ======
The accompanying notes are an integral part of these financial statements.
F-42
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
Terms and abbreviations appearing in these Notes to Unaudited Condensed
Consolidated Financial Statements are explained in the Glossary of Terms and
Abbreviations.
1. INTERIM FINANCIAL STATEMENTS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies of PPL Energy Supply are summarized in
the Notes to the Consolidated Financial Statements for the years ended December
31, 2000, 1999 and 1998. These interim financial statements should be read in
conjunction with those financial statements and the accompanying footnotes.
Management believes that the accompanying unaudited condensed consolidated
financial statements reflect all adjustments, consisting of normal recurring
items, necessary for a fair statement of results for the interim periods
presented. Certain amounts in the December 31, 2000 financial statements have
been reclassified to conform to the presentation in the September 30, 2001
financial statements.
2. SEGMENT AND RELATED INFORMATION
PPL Energy Supply's reportable segments are Supply and International. The
Supply group primarily consists of the domestic energy marketing and generation
operations of PPL EnergyPlus and PPL Generation, as well as PPL Global's
domestic development operations. The International group includes PPL Global's
responsibility for the acquisition, development, ownership and operation of
international energy projects. The majority of PPL Global's international
investments are located in the U.K., Chile, El Salvador and Brazil. Segments
include direct charges, as well as an allocation of indirect corporate costs,
for services provided by PPL Services. These services costs include functions
such as financial, legal, human resources, and information services.
Financial data for PPL Energy Supply's business segments are as follows
(millions of dollars):
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- -------------
2001 2000 2001 2000
------ ------ ------ ------
INCOME STATEMENT DATA
Revenues from external customers
Supply................................... $ 997 $1,099 $2,983 $1,660
International............................ 136 81 437 312
------ ------ ------ ------
1,133 1,180 3,420 1,972
Intersegment revenues
N/A--There are no intersegment revenues.
Net income
Supply................................... 167 115 454 89
International............................ (2) 8 36 31
------ ------ ------ ------
$ 165 $ 123 $ 490 $ 120
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- ------------
BALANCE SHEET DATA
Total assets
Supply......... $5,648 $5,121
International.. 2,466 2,342
------ ------
$8,114 $7,463
F-43
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES--AT EQUITY
PPL Energy Supply's investments in unconsolidated affiliates accounted for
under the equity method were $767 million and $800 million at September 30,
2001 and December 31, 2000. The most significant investment was PPL Global's
investment in WPDH, which was $511 million at September 30, 2001 and $479
million at December 31, 2000. At September 30, 2001, PPL Global had a 51%
equity ownership interest in WPDH, but shared joint control with Mirant.
Accordingly, PPL Global accounts for its investment in WPDH (and other
investments where it has majority ownership but lacks voting control) under the
equity method of accounting.
Summarized below is information from the financial statements of
unconsolidated affiliates, as included in PPL Energy Supply's consolidated
financial statements under the equity method for the periods noted (millions of
dollars):
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------- -------------
2001 2000 2001 2000
---- ---- ---- ----
INCOME STATEMENT DATA
Revenues............. $148 $100 $480 $338
Operating Income..... 75 42 242 165
Net Income........... 68 16 212 98
4. SALES TO OTHER ELECTRIC UTILITIES
Under FERC-approved interconnection and power supply agreements, PPL
EnergyPlus supplied capacity and energy to UGI. This agreement was terminated
in February 2001.
PPL EnergyPlus had a contract to provide BG&E with 129,000 kilowatts, or
6.6%, of PPL Susquehanna's share of capacity and related energy from the
Susquehanna station. PPL EnergyPlus provided 407 million kWh to BG&E through
May 2001, at which point the contract ended.
PPL Montana provides power to Montana Power under two wholesale transition
sales agreements. These agreements expire in December 2001 and June 2002. See
Note 13 regarding a new supply agreement beginning in July 2002.
5. CREDIT ARRANGEMENTS AND FINANCING ACTIVITIES
CREDIT ARRANGEMENTS
In June 2001, PPL Energy Supply entered into two credit facilities: a $600
million 364-day facility and a $500 million three-year facility. Obligations of
PPL Energy Supply under these credit facilities were guaranteed by PPL. The PPL
guarantee fell away in connection with PPL Energy Supply's issuance of senior
notes described in Note 13. In addition, in June 2001, PPL Energy Supply
entered into a 364-day revolving credit facility with PPL Capital Funding. PPL
has guaranteed PPL Capital Funding's obligations under this agreement. At
September 30, 2001, no borrowings were outstanding under any of these
facilities.
F-44
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
PPL Montana has a $100 million Tranche B Revolver which matures in November
2002. The maturity date may be extended with the consent of the lenders. The
Tranche B Revolver provides that up to $75 million of the commitment may be
used to cause lenders to issue letters of credit. In the event that PPL Montana
were to draw upon this facility and cause lenders to issue letters of credit on
its behalf, PPL Montana would be required to reimburse the issuing lenders. At
September 30, 2001, $50 million was outstanding under the Tranche B Revolver
and $25 million of letters of credit were issued.
In April 2001, PPL Montana executed a new credit facility to allow for
incremental letter of credit capacity of $150 million. At September 30, 2001,
there were no amounts outstanding under this facility. PPL has executed a
commitment to the lenders under PPL Montana's $150 million credit facility that
PPL will provide (or cause PPL Energy Supply to provide) letters of credit at
such times and in such amounts as are necessary to permit PPL Montana to remain
in compliance with its fixed price forward energy contracts or its derivative
financial instruments entered into to manage energy price risks, to the extent
that PPL Montana cannot provide such letters of credit under its existing
credit agreements. No such letters of credit had been issued as of September
30, 2001.
FINANCING ACTIVITIES
In May 2001, a PPL Global subsidiary entered into an operating lease
arrangement, initially for $900 million and increased in July 2001 to $1.06
billion upon syndication, for the development, construction and operation of
several commercial power generation facilities. Certain obligations of the PPL
Global subsidiary under this operating lease have been guaranteed by PPL Energy
Supply. In addition, PPL had guaranteed PPL Energy Supply's obligations. PPL's
guarantee of these obligations fell away in connection with PPL Energy Supply's
issuance of senior notes, described in Note 13.
6. ACQUISITIONS, DEVELOPMENT AND DIVESTITURES
DOMESTIC GENERATION PROJECTS
In January 2001, PPL Montour acquired an additional interest in the
coal-fired Conemaugh Power Plant from Potomac Electric Power Company. Under the
terms of the acquisition agreement, PPL Montour and a subsidiary of Allegheny
Energy, Inc. jointly acquired a 9.72% interest in the 1,711-megawatt plant. PPL
Montour paid $78 million for this additional 83-megawatt interest. The purchase
increased PPL Montour's ownership interest to 16.25% in the two-unit plant.
In April 2001, PPL Global announced plans to develop a power plant near
University Park in Chicago, Illinois. The plant would be a 540-megawatt,
simple-cycle, natural gas-fired electric generation facility and is expected to
be in service in 2002 at a captial cost of approximately $305 million. PPL
Susquehanna also announced plans to increase the capacity of its Susquehanna
nuclear plant by 100 megawatts with the installation of more efficient steam
turbines on each of the two units. These improvements will be made in 2003 and
2004 and are expected to cost approximately $120 million.
INTERNATIONAL DISTRIBUTION PROJECTS
In January 2001, PPL Global purchased an additional 5.6% of CGE from the
Claro group, bringing its total investment to $141 million, or about 8.5%. CGE
provides electricity delivery service to 1.4 million customers in Chile, and
natural gas delivery service to 200,000 customers in Santiago.
F-45
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
In May 2001, WPDL successfully completed the sale of Hyder's water business,
Welsh Water, to the Welsh firm Glas Cymru Cyfyngedig for one British pound
sterling and the assumption of all of Welsh Water's debt.
7. COMMITMENTS AND CONTINGENT LIABILITIES
PPL Energy Supply and its related subsidiaries are involved in numerous
legal proceedings, claims and litigation in the ordinary course of business.
PPL Energy Supply and its subsidiaries cannot predict the ultimate outcome of
such matters, or whether such matters may result in material liabilities.
WHOLESALE ENERGY COMMITMENTS
As part of the purchase of generation assets from Montana Power, PPL Montana
agreed to supply electricity under two wholesale transition service agreements.
In addition, PPL Montana assumed a power purchase agreement and another power
sales agreement. In accordance with purchase accounting guidelines, PPL Montana
recorded a liability of $118 million as the estimated fair value of these
agreements at the acquisition date. This liability is being amortized over the
agreement terms as adjustments to "Wholesale energy marketing and trading"
revenues and "Energy purchases" on the Statement of Income. The unamortized
balance at September 30, 2001 was $83 million.
LIABILITY FOR ABOVE MARKET NUG CONTRACTS
At June 30, 1998, PPL Electric recorded an $854 million loss accrual for
above market contracts with NUGs. Effective January 1999, PPL Electric began
reducing this liability as an offset to "Energy purchases" on the Statement of
Income. This reduction is based on the estimated timing of the purchases from
the NUGs and projected market prices for this generation. The final existing
NUG contract expires in 2014. In connection with the corporate realignment,
effective July 1, 2000, the remaining balance of this liability was transferred
to PPL EnergyPlus. The liabilities associated with these above market NUG
contracts were $605 million at September 30, 2001.
COMMITMENTS--ACQUISITIONS AND DEVELOPMENT ACTIVITIES
PPL Global and its subsidiaries have committed additional capital and
extended loans to certain affiliates, joint ventures and partnerships in which
they have an interest. At September 30, 2001, PPL Global and its subsidiaries
had approximately $889 million of such commitments. The majority of these
commitments are for the lease of turbine generators and related equipment for
domestic generation projects.
MPSC ORDER
In June 2001, the MPSC issued an order (MPSC Order) in which it found that
Montana Power must continue to provide electric service to its customers at
tariffed rates until its transition plan under the Montana Electricity Utility
Industry Restructuring and Customer Choice Act is finally approved, and that
purchasers of generating assets from Montana Power must provide electricity to
meet Montana Power's full load requirements at prices to Montana Power that
reflect costs calculated as if the generation assets had not been sold. PPL
Montana purchased Montana Power's interest in two coal-fired plants and 11
hydroelectric units in 1999.
In July 2001, PPL Montana filed a complaint against the MPSC with the U.S.
District Court in Helena, Montana, challenging the MPSC Order. In its
complaint, PPL Montana asserted, among other things, that the
F-46
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
Federal Power Act preempts states from exercising regulatory authority over
sale of electricity in wholesale markets, and requested the court to declare
the MPSC action preempted, unconstitutional and void. In addition, the
complaint requested that the MPSC be enjoined from seeking to exercise any
authority, control or regulation of wholesale sales from PPL Montana's
generating assets.
At this time, PPL Energy Supply cannot predict the outcome of the
proceedings related to the MPSC Order, whether the new supply agreement with
Montana Power will be accepted by filing by the FERC, what actions the MPSC,
the Montana Legislature or any other governmental authority may take on these
or related matters, or the ultimate impact on PPL Energy Supply and PPL Montana
of any of these matters.
MONTANA POWER SHAREHOLDERS' LITIGATION
In August 2001, a purported class-action lawsuit was filed by a group of
shareholders of Montana Power against Montana Power, the directors of Montana
Power, certain unnamed advisors and consultants of Montana Power, and PPL
Montana. The plaintiffs allege, among other things, that Montana Power was
required to, and did not, obtain shareholder approval of the sale of Montana
Power's generation assets to PPL Montana in 1999. Although most of the claims
in the complaint are against Montana Power, its board of directors, and its
consultants and advisors, one claim is asserted against PPL Montana. That claim
alleges that PPL Montana was privy to and participated in a strategy whereby
Montana Power would sell its generation assets to PPL Montana without first
obtaining Montana Power shareholder approval, and that PPL Montana has made net
profits in excess of $100 million as the result of this illegal sale. The
complaint requests that the court impose a "resulting and/or constructive
trust" on both the generation assets themselves and the alleged $100 million of
net profits realized by PPL Montana from such assets.
The complaint also seeks 10% per annum interest on the amounts subject to
the trust. PPL Montana is unable to predict the outcome of this matter.
ENERGY SUPPLY TO ENERGY WEST RESOURCES, INC.
In July 2001, PPL Montana filed an action in state court and a responsive
pleading in federal court, both related to a breach of contract by Energy West
Resources, Inc. (Energy West), a Great Falls, Montana-based energy aggregator.
In the federal action, PPL Montana had requested that the court refrain from
issuing a preliminary injunction and lift a temporary restraining order that
had been issued in July 2001, prohibiting PPL Montana from seeking to terminate
the contract under which it supplies energy to Energy West. In the state
action, PPL Montana is seeking a judgment that Energy West violated the terms
of the supply contract and should pay damages of at least $7.5 million.
Subsequently, in July 2001, the federal court judge dissolved the temporary
restraining order and stayed all proceedings in the case pending resolution by
the FERC of a request by PPL Montana to terminate the contract between PPL
Montana and Energy West. In September 2001, the FERC issued an order rejecting
PPL Montana's request to terminate the contract. The FERC order was without
prejudice, and PPL Montana may refile its notice of termination after the
conclusion of the court proceedings. All litigation in this matter has been
consolidated in the U. S. District Court for the District of Montana, Great
Falls Division, and is proceeding in that forum. PPL Montana cannot predict the
ultimate outcome of these proceedings.
NUCLEAR INSURANCE
PPL Susquehanna is a member of certain insurance programs which provide
coverage for property damage to members' nuclear generating stations.
Facilities at the Susquehanna station are insured against property
F-47
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
damage losses up to $2.75 billion under these programs. PPL Susquehanna is also
a member of an insurance program which provides insurance coverage for the cost
of replacement power during prolonged outages of nuclear units caused by
certain specified conditions. Under the property and replacement power
insurance programs, PPL Susquehanna could be assessed retroactive premiums in
the event of the insurers' adverse loss experience. At September 30, 2001, this
maximum assessment was about $20 million.
PPL Susquehanna's public liability for claims resulting from a nuclear
incident at the Susquehanna station is limited to about $9.5 billion under
provisions of The Price Anderson Amendments Act of 1988. PPL Susquehanna is
protected against this liability by a combination of commercial insurance and
an industry assessment program. In the event of a nuclear incident at any of
the reactors covered by The Price Anderson Amendments Act of 1988, PPL
Susquehanna could be assessed up to $176 million per incident, payable at $20
million per year.
ENVIRONMENTAL MATTERS
AIR
The Clean Air Act deals, in part, with acid rain, attainment of federal
ambient ozone standards and toxic air emissions. PPL Energy Supply subsidiaries
are in substantial compliance with the Clean Air Act.
The DEP has finalized regulations requiring further seasonal (May-June) NOx
reductions to 80% from 1990 levels starting in 2003. These further reductions
are based on the requirements of the Northeast Ozone Transport Region
Memorandum of Understanding and two EPA ambient ozone initiatives: the
September 1998 EPA State Implementation Plan (SIP) call (i.e., EPA's
requirement for states to revise their SIPs) issued under Section 110 of the
Clean Air Act, requiring reductions from 22 eastern states, including
Pennsylvania; and the EPA's approval of petitions filed by Northeastern states,
requiring reductions from sources in 12 Northeastern states and Washington
D.C., including PPL Energy Supply sources. The EPA's SIP-call was substantially
upheld by the D.C. Circuit Court of Appeals in an appeals proceeding.
Although the Court extended the implementation deadline to May 2004, the DEP
has not changed its rules accordingly. PPL Energy Supply expects to achieve the
2003 NOx reductions with the recent installation of SCR technology on the
Montour units and possibly SCR or SNCR on a Brunner Island unit.
The EPA has also developed a revised ambient ozone standard and a new
standard for ambient fine particulates. These standards were challenged and
remanded to the EPA by the D.C. Circuit Court of Appeals in 1999. However, on
appeal to the United States Supreme Court, the D.C. Circuit Court's decision
was reversed in part and remanded to the D.C. Circuit Court. The new
particulates standard, if finalized, may require further reductions in SO\\2\\
for certain PPL Energy Supply subsidiaries and year-round NOx reductions
commencing in 2010-2012 at SIP-call levels in Pennsylvania, and at slightly
less stringent levels in Montana. The revised ozone standard, if finalized, is
not expected to have a material effect on facilities of PPL Energy Supply
subsidiaries.
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 emissions should be regulated, and has determined that mercury
emissions must be regulated. In this regard, the EPA is expected to develop
regulations by 2004.
In 1999, the EPA initiated enforcement actions against several 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
F-48
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
commenced enforcement activities against other utilities. At this time, PPL
Energy Supply is unable to predict whether such EPA enforcement actions will be
brought with respect to any of its affiliates' plants. However, the EPA
regional offices that regulate plants in Pennsylvania (Region III) and Montana
(Region VIII) have indicated an intention to issue information requests to all
utilities in their jurisdiction, and the Region VIII Office has issued such a
request to PPL Montana's Corette plant. PPL Energy Supply has responded to the
information request. PPL Energy Supply cannot presently predict what, if any,
action the EPA might take. The EPA has reportedly suspended further enforcement
activity pending an interagency review of the "New Source" program. Should the
EPA initiate one or more enforcement actions against PPL Energy Supply,
compliance with any such EPA enforcement actions could result in additional
capital and operating expenses in amounts which are not now determinable, but
which could be significant.
The New Jersey Department of Environmental Protection and some New Jersey
residents have raised environmental concerns with respect to the Martins Creek
Plant, particularly with respect to SO\\2 \\emissions. PPL Martins Creek is
discussing these concerns with the New Jersey Department of Environmental
Protection. In addition, the plant experienced several opacity violations in
the first and second quarters of 2001. The cost of addressing New Jersey's
SO\\2\\ concerns and the opacity issues is not now determinable, but could be
significant.
WATER/WASTE
The final NPDES permit for the Montour plant contains stringent limits for
iron discharges. The results of a toxic reduction study show that additional
water treatment facilities or operational changes are needed at this station. A
plan for these changes has been developed and was submitted to the DEP in
August 2001.
A draft NPDES permit has been issued to the Brunner Island plant. The draft
permit contains a provision requiring further studies on the thermal impact of
the cooling water discharge from the plant. Depending on the outcome of these
studies, the plant could be subject to capital and operating costs that are not
now determinable, but could be significant
In 2000, the EPA significantly tightened the water quality standard for
arsenic. However, the EPA has now withdrawn the standard in order to further
study the matter. A tightened standard may require PPL Energy Supply
subsidiaries to further treat wastewater and/or take abatement action at
several of its power plants, the cost of which is not now determinable, but
which could be significant.
The EPA's proposed requirements for new or modified water intake structures
will affect where generating facilities are built, will establish intake design
standards, and could lead to requirements for cooling towers at new power
plants. These proposed regulations are expected to be finalized by November
2001. The rule could require new or modified cooling towers at one or more PPL
Energy Supply subsidiary stations. Another new rule, expected to be finalized
in 2003, will address existing structures. Each of these rules could impose
significant costs on PPL Energy Supply, which are not now determinable.
OTHER REMEDIATION
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 effects on PPL Energy Supply and PPL Montana of any
such changes in laws or regulations or any such increase in legal actions are
not now determinable, but could be significant.
F-49
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
Under the Montana Power Asset Purchase Agreement, PPL Montana is indemnified
by Montana Power for any pre-acquisition environmental liabilities. However,
this indemnification is conditioned on certain circumstances that could result
in PPL Montana and Montana Power sharing in certain costs within limits set
forth in the agreement.
Future cleanup or remediation work at sites currently under review, or at
sites not currently identified, may result in material additional operating
costs for PPL Energy Supply subsidiaries that cannot be estimated at this time.
GENERAL
Due to the environmental issues discussed above or others, PPL Energy Supply
subsidiaries may be required to modify, replace or cease operating certain
facilities to comply with statutes, regulations and actions by regulatory
bodies or courts. In this regard, PPL Energy Supply subsidiaries also may incur
capital expenditures, operating expenses and other costs in amounts which are
not now determinable, but which could be significant.
CREDIT SUPPORT
PPL provides certain guarantees for PPL Energy Supply and its subsidiaries.
As of September 30, 2001, PPL had guaranteed certain obligations of PPL
EnergyPlus for up to $1 billion under power purchase and sales agreements. PPL
had also guaranteed certain obligations of PPL Energy Supply subsidiaries,
totaling $679 million at September 30, 2001.
See Note 5 for discussion of credit support for PPL Montana and guarantees
under PPL Energy Supply's credit facilities.
8.RELATED PARTY TRANSACTIONS
PPL, through PPL Capital Funding and other subsidiaries, provides certain
funding for PPL Energy Supply and its subsidiaries. Such funding includes loans
that are due on demand and interest is charged at a rate based on PPL Capital
Funding's short-term borrowing rate. In addition, PPL Energy Supply has notes
receivable from other affiliates of PPL. These notes were issued in conjunction
with PPL's overall cash management strategies. Interest earned on loans to
affiliated companies and interest incurred on borrowings from affiliated
companies are included in "Other Income--net" and "Interest Expense,"
respectively, in the Statement of Income. Intercompany interest income (in
millions) was $19 and $14 for the three months ended, and $38 and $21 for the
nine months ended September 30, 2001 and 2000, respectively. Intercompany
interest expense (in millions) was $0 and $28 for the three months ended, and
$26 and $61 for the nine months ended September 30, 2001 and 2000,
respectively. Notes receivable from affiliated companies at September 30, 2001
was $1.4 billion.
PPL Global provided temporary financing to WPDL and WPDH in connection with
the acquisition of Hyder. The outstanding loan receivables and accrued
interest, 154.5 million British pounds sterling (approximately $220 million),
were repaid in May 2001.
At December 31, 2000, PPL Global had a $135 million note payable to an
affiliate of WPDH. The note was denominated in U.S. dollars, and provided for
interest at market rates. PPL Global repaid this note in January 2001.
As part of the corporate realignment, PPL Electric entered into power
purchase agreements with PPL EnergyPlus for the purchase of electricity to meet
its obligations as a PLR for customers who have not selected an
F-50
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
alternative supplier under the Customer Choice Act. Under the terms of these
agreements, this electricity is purchased by PPL Electric at the applicable
shopping credits authorized by the PUC, plus nuclear decommissioning costs,
less state taxes. These sales totaled $347 million and $969 million for the
three and nine months ended September 30, 2001, and are included in "Wholesale
energy marketing and trading" on the Statement of Income. These agreements end
on December 31, 2001. See Note 12 for a discussion of the new agreement with
PPL EnergyPlus, whereby PPL EnergyPlus will provide electricity for PPL
Electric's PLR load obligation through 2009.
Also as part of the corporate realignment, PPL Electric executed a
reciprocal contract with PPL EnergyPlus to sell electricity purchased under
contracts with NUGs. PPL Electric purchases electricity from the NUGs at
contractual rates, and then sells the electricity at the same price to PPL
EnergyPlus. These expenses totaled $44 million and $132 million for the three
and nine months ended September 30, 2001, and are included in "Energy
purchases" on the Statement of Income.
Corporate functions such as financial, legal, human resources and
information services were transferred to PPL Services in the corporate
realignment. PPL Services bills the respective PPL subsidiaries for the cost of
such services when they can be specifically identified. The cost of these
services that are not directly charged to PPL subsidiaries are allocated to
certain of the subsidiaries based on the relative capital invested by PPL in
these subsidiaries. For the three and nine months ended September 30, 2001, PPL
Services charged PPL Energy Supply subsidiaries approximately $23 and $57
million for direct expenses, and allocated these entities approximately $10 and
$27 million of overhead costs.
9.DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
PPL Energy Supply adopted SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities," on January 1, 2001. Upon adoption and in accordance
with the transition provisions of SFAS 133, PPL Energy Supply recorded a
cumulative-effect credit of $11 million in earnings, included as an increase to
"Wholesale energy marketing and trading" revenues and a decrease to "Energy
purchases" on the Statement of Income. PPL Energy Supply also recorded a
cumulative-effect charge of $182 million in accumulated other comprehensive
income, a component of Member's Equity. As of September 30, 2001, the balance
in accumulated other comprehensive income related to unrealized gains and
losses on qualifying derivatives was a gain of $33 million, as a result of
reclassifying part of the transition adjustment into earnings, changes in
market prices and the adoption of Derivatives Implementation Group issue C15
(see discussion in "Implementation Issues" below).
MANAGEMENT OF MARKET RISK EXPOSURES
PPL Energy Supply's market risk exposure is the adverse effect on the value
of a transaction that results from a change in commodity prices. The market
risk associated with commodity prices is managed by the establishment and
monitoring of parameters that limit the types and degree of market risk that
may be undertaken. PPL Energy Supply actively manages the market risk inherent
in its positions. The PPL Board of Directors has adopted risk management
policies to manage the risk exposures related to energy prices. These policies
monitor and assist in controlling these market risks and use derivative
instruments to manage some associated commodity activities.
PPL Energy Supply's derivative activities are subject to the management,
direction and control of the Risk Management Committee (RMC). The RMC is
composed of the chief financial officer and other officers of PPL. The RMC
reports to the PPL Board of Directors on the scope of its derivative
activities. The RMC sets forth risk-management philosophy and objectives
through a corporate policy, provides guidelines for derivative-instrument
usage, and establishes procedures for control and valuation, counterparty
credit approval, and the monitoring and reporting of derivative activity.
F-51
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
PPL Energy Supply utilizes forward contracts, futures contracts, options and
swaps as part of its risk management strategy to minimize unanticipated
fluctuations in earnings caused by commodity prices. All derivatives are
recognized on the balance sheet at their fair value, unless they qualify for
the "normal purchases and sales" exclusion permitted by SFAS 133 (see
discussion in "Implementation Issues" below).
FAIR VALUE HEDGES
PPL Energy Supply enters into financial contracts to hedge a portion of the
fair values of firm commitments of forward electricity sales. These contracts
range in maturity through 2004. For the three and nine months ended September
30, 2001, PPL Energy Supply did not recognize any gains or losses resulting
from the ineffective portion of fair value hedges or from firm commitments that
no longer qualified as fair value hedges.
CASH FLOW HEDGES
PPL Energy Supply enters into physical and financial contracts including,
forwards, futures and swaps, to hedge the price risk associated with electric,
gas and oil commodities. These contracts range in maturity through 2008. For
the three and nine months ended September 30, 2001, PPL Energy Supply recorded
a net-of-tax loss of $14 million and a net-of-tax gain of $9 million,
respectively (reported in other comprehensive income).
As a result of an unplanned outage and changes in other economic conditions,
PPL Energy Supply discontinued certain cash flow hedges which resulted in a net
loss of $22 million for the nine months ended September 30, 2001 (reported in
"Wholesale energy marketing and trading" revenues in the Statement of Income).
There was no gain or loss from the discontinuation of cash flow hedges for the
three months ended September 30, 2001. The impact on the financial statements
resulting from cash flow hedge ineffectiveness was immaterial.
As of September 30, 2001, the deferred net loss on derivative instruments in
accumulated other comprehensive income that are expected to be reclassified
into earnings during the next twelve months was $4 million.
IMPLEMENTATION ISSUES
On June 29, 2001, the FASB issued definitive guidance on Derivatives
Implementation Group issue C15: "Scope Exceptions: Normal Purchases and Normal
Sales Exception for Option-Type Contracts and Forward Contracts in
Electricity." Issue C15 provides additional guidance on the classification and
application of SFAS 133 relating to purchases and sales of electricity
utilizing forward contracts and options. This guidance became effective as of
July 1, 2001. On October 10, 2001 the FASB revised the guidance in Issue C15,
principally related to the eligibility of options for the normal purchases and
normal sales exception. The revised guidance is effective as of January 1, 2002.
Purchases and sales of forward electricity and option contracts that require
physical delivery and which are expected to be used or sold by the reporting
entity in the normal course of business would generally be considered "normal
purchases and normal sales" under SFAS 133. These transactions, while within
the scope of SFAS 133, are not required to be marked to fair value in the
financial statements because they qualify for the normal purchases and sales
exception. As of September 30, 2001, accumulated other comprehensive income
included an after tax gain of $17 million related to forward transactions
classified as cash flow hedges prior to the Issue C15 guidance. This gain will
be reversed from accumulated other comprehensive income as the contracts
deliver through 2008.
F-52
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
UNREALIZED GAINS/LOSSES ON DERIVATIVES QUALIFIED AS HEDGES
(MILLIONS OF DOLLARS)
(AFTER TAX)
SEPTEMBER 30, 2001
-----------------------
THREE MONTHS NINE MONTHS
ENDED ENDED
------------ -----------
Unrealized gains on derivatives qualified as hedges, beginning of period:. $33 $ 0
Unrealized gains (losses) arising during period:
Cumulative effect of change in accounting principle at January 1, 2001. (182)
Other unrealized gains (losses)........................................ (4) 215
Less: reclassification for net (losses) gains included in net income... (4)
--- -----
Other comprehensive income................................................ 0 33
--- -----
Unrealized gains on derivatives qualified as hedges, end of period........ $33 $ 33
=== =====
10. NEW ACCOUNTING STANDARDS
SFAS 141
In June 2001, the FASB issued SFAS 141, "Business Combinations," which
eliminates the pooling-of-interest method of accounting for business
combinations and requires the use of the purchase method. In addition, it
requires the reassessment of intangible assets to determine if they are
appropriately classified either separately or within goodwill. SFAS 141 is
effective for business combinations initiated after June 30, 2001. PPL Energy
Supply adopted SFAS 141 on July 1, 2001 with no material impact on the
financial statements.
SFAS 142
In June 2001, the FASB issued SFAS 142, "Goodwill and Other Intangible
Assets," which eliminates the amortization of goodwill and other acquired
intangible assets with indefinite economic useful lives. SFAS 142 requires an
annual impairment test of goodwill and other intangible assets that are not
subject to amortization. SFAS 142 is effective for fiscal years beginning after
December 15, 2001. The impact of adopting SFAS 142 is not yet determinable, but
may be material.
SFAS 143
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations," on the accounting for obligations associated with the retirement
of long-lived assets. SFAS 143 requires a liability to be recognized in the
financial statements for retirement obligations meeting specific criteria.
Measurement of the initial obligation is to approximate fair value, with an
equivalent amount recorded as an increase in the value of the capitalized
asset. The asset will be depreciated in accordance with normal depreciation
policy and the liability will be increased, with a charge to the income
statement, until the obligation is settled. SFAS 143 is effective for fiscal
years beginning after June 15, 2002. The potential impact of adopting SFAS 143
is not yet determinable, but may be material.
F-53
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
SFAS 144
In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," that replaces SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
For long-lived assets to be held and used, SFAS 144 retains the requirements of
SFAS 121 to (a) recognize an impairment loss only if the carrying amount is not
recoverable from undiscounted cash flows and (b) measure an impairment loss as
the difference between the carrying amount and fair value of the asset. For
long-lived assets to be disposed of, SFAS 144 establishes a single accounting
model based on the framework established in SFAS 121. The accounting model for
long-lived assets to be disposed of by sale applies to all long-lived assets,
including discontinued operations, and replaces the provisions of APB Opinion
No. 30, "Reporting the Results of Operations--Reporting the Effects of Disposal
of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," for the disposal of segments of a business.
SFAS 144 also broadens the reporting of discontinued operations. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. The impact of
adopting SFAS 144 is not yet determinable, but is expected to be immaterial.
11. SALES TO CALIFORNIA INDEPENDENT SYSTEM OPERATOR AND TO OTHER PACIFIC
NORTHWEST PURCHASERS
PPL Energy Supply, through PPL Montana, has made approximately $18 million
of sales to the California ISO, for which PPL Energy Supply has not yet been
paid in full. Given the myriad of electricity supply problems presently faced
by the California electric utilities and the California ISO, PPL Energy Supply
cannot predict when it will receive payment. As of September 30, 2001, PPL
Energy Supply has fully reserved for possible underrecoveries of payments for
these sales.
Litigation arising out of the California electric supply situation has been
filed at the FERC and in California courts against sellers of energy to the
California ISO. The plaintiffs and intervenors in these proceedings allege
abuses of market power, manipulation of market prices, unfair trade practices
and violations of state antitrust laws, 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. Certain of PPL Energy Supply's subsidiaries
have intervened in the FERC proceedings in order to protect their interests,
but have not been named as defendants in any of the court actions. In addition,
attorneys general in several western states, including California, have begun
investigations related to the electricity supply situation in California and
other western states. The FERC has determined that all sellers of energy in the
California markets, including PPL Montana, should be subject to refund
liability for the period beginning October 2, 2000 through June 20, 2001 and
has initiated an evidentiary hearing concerning refund amounts. The FERC also
is considering whether to order refunds for sales made in the Pacific
Northwest, including sales made by PPL Montana. The FERC Administrative Law
Judge assigned to this proceeding has recommended that no refunds be ordered
for sales into the Pacific Northwest. The FERC presently is considering this
recommendation. PPL Montana cannot predict whether or the extent to which any
of its subsidiaries will be the target of any governmental investigation or
named in these lawsuits, refund proceedings or other lawsuits, the outcome of
any such proceedings or whether the ultimate impact on PPL Montana of the
electricity supply situation in California and other western states will be
material.
12. SUPPLY CONTRACT TO PPL ELECTRIC
PPL EnergyPlus currently has a full requirements contract to provide PPL
Electric with electricity sufficient for PPL Electric to meet its PLR
obligations under the Pennsylvania Customer Choice Act at the pre-set prices
F-54
PPL ENERGY SUPPLY, LLC
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
SEPTEMBER 30, 2001
that PPL Electric charges such customers through the end of 2001. PPL
EnergyPlus provides all of PPL Electric's supply needs at the price cap level
through 2001, regardless of the prevailing market price. PPL Electric's PLR
obligation extends through 2009. PPL Electric solicited bids to contract with
energy suppliers to meet its obligations to deliver energy to its customers
from 2002 through 2009. PPL EnergyPlus was the low bidder, and in June 2001
entered into a contract to provide electricity to PPL Electric sufficient for
PPL Electric to meet its PLR obligation through 2009, at the pre-set rates PPL
Electric is entitled to charge its customers during this period. In July 2001,
the energy supply contract was approved by the PUC and accepted for filing by
the FERC.
Under this contract, PPL EnergyPlus will also receive a $90 million payment
to offset differences between the revenues expected under the capped prices and
projected market prices through the life of the supply agreement (as projected
by PPL EnergyPlus at the time of its bid). The contract resulted in PPL
EnergyPlus having an eight-year contract at current market prices. PPL has
guaranteed the obligations of PPL EnergyPlus under the new contract. PPL
Electric made the $90 million payment to PPL EnergyPlus in August 2001.
13. SUBSEQUENT EVENTS
ENERGY SUPPLY TO MONTANA POWER
In October 2001, PPL EnergyPlus reached an agreement to supply Montana Power
with an aggregate of 450 megawatts of energy to be supplied by PPL Montana. The
delivery term of this new contract is for five years beginning July 1, 2002,
which is the day after the termination date of the last of the two existing
contracts, pursuant to which PPL Montana presently supplies energy to Montana
Power for its default supply.
Under the agreement, PPL EnergyPlus will supply 300 megawatts of baseload
electricity and 150 megawatts of on-peak electricity. The agreement has been
filed for acceptance with the FERC.
PPL ENERGY SUPPLY DEBT OFFERING
In October 2001, PPL Energy Supply sold $500 million aggregate principal
amount of its 6.40% senior notes due 2011, in a private placement. In
connection with the issuance of the senior notes, PPL Energy Supply entered
into a registration rights agreement pursuant to which PPL Energy Supply
agreed, under certain circumstances, to conduct an exchange offer or file a
shelf registration statement with respect to the senior notes. Proceeds of the
senior note offering will be used to fund generation development and for
general corporate purposes.
F-55
PPL ENERGY SUPPLY, LLC
GLOSSARY OF TERMS AND ABBREVIATIONS
BANGOR HYDRO--Bangor Hydro-Electric Company.
BG&E--Baltimore Gas & Electric Company.
CEMAR--Companhia Energetica do Maranhao, a Brazilian electric distribution
company in which PPL Global has a majority ownership interest.
CGE--Compania General Electricidad, SA, a distributor of energy in Chile and
Argentina, in which PPL Global has a minority ownership interest.
CLEAN AIR ACT--Federal legislation enacted to address certain environmental
issues related to air emissions including acid rain, ozone and toxic air
emissions.
CTC--competitive transition charge on customer bills to recover allowable
transition costs under the Customer Choice Act.
CUSTOMER CHOICE ACT--(Pennsylvania Electricity Generation Customer Choice and
Competition Act)--legislation enacted to restructure the state's electric
utility industry to create retail access to a competitive market for generation
of electricity.
DEP--Pennsylvania Department of Environmental Protection.
DERIVATIVE--a financial instrument or other contract with all three of the
following characteristics:
a. It has (1) one or more underlying instruments or contracts and (2) one or
more notional amounts or payment provisions or both. Those terms determine
the amount of the settlement or settlements, and, in some cases, whether or
not a settlement is required.
b. It requires no initial net investment or an initial net investment that is
smaller than would be required for other types of contracts that would be
expected to have a similar response to changes in market factors.
c. Its terms require or permit net settlement, it can readily be settled net
by a means outside the contract, or it provides for delivery of an asset
that puts the recipient in a position not substantially different from net
settlement.
EC--Electricidad de Centroamerica, S.A. de C.V, an El Salvadoran holding
company and the majority owner of Del Sur. PPL Global has 100% ownership of EC.
EITF (Emerging Issues Task Force)--an organization that aids the FASB in
identifying emerging issues that may require FASB action.
EMEL--Empresas Emel, S.A., a Chilean electric distribution holding company of
which PPL Global has majority ownership.
ENERGY MARKETING CENTER--business unit responsible for marketing and trading
wholesale energy and capacity. Effective July 1, 2000, the Energy Marketing
Center is part of PPL EnergyPlus.
EPA--Environmental Protection Agency.
FASB (Financial Accounting Standards Board)--a rulemaking organization that
establishes financial accounting and reporting standards.
FERC (Federal Energy Regulatory Commission)--federal agency that regulates
interstate transmission and wholesale sales of electricity and related matters.
GAAP--Generally accepted accounting principles.
HYDER--Hyder Limited, a subsidiary of WPDL and previous owner of South Wales
Electricity plc. In March 2001, South Wales Electricity plc was sold to WPDH.
IBEW--International Brotherhood of Electrical Workers.
ICP--Incentive Compensation Plan.
ICPKE--Incentive Compensation Plan for Key Employees.
ISO--Independent System Operator.
JCP&L--Jersey Central Power & Light Company.
LIBOR--London Inter-bank Offered Rate.
MIRANT--Mirant Corporation, formerly Southern Energy Inc., a diversified energy
company based in Atlanta. PPL Global and Mirant jointly own WPDH and WPD
Investment Holdings Limited, the parent company of WPDL.
F-56
MONTANA POWER--The Montana Power Company, a Montana-based company engaged in
diversified energy and communication-related businesses. Montana Power sold its
generating assets to PPL Montana in December 1999.
NOX--nitrogen oxide.
NPDES--National Pollutant Discharge Elimination System.
NRC (Nuclear Regulatory Commission)--federal agency that regulates operation of
nuclear power facilities.
NUGS (Non-Utility Generators)--generating plants not owned by public utilities,
whose electrical output must be purchased by utilities under the PURPA if the
plant meets certain criteria.
PJM (PJM Interconnection, LLC)--operates the electric transmission network and
electric energy market in the mid-Atlantic region of the U.S.
PLR--Provider of last resort, refers to PPL Electric providing electricity to
retail customers within its delivery territory who have chosen not to shop for
electricity under the Customer Choice Act.
PPL--PPL Corporation, the parent holding company of PPL Electric, PPL Energy
Funding and other subsidiaries.
PPL CAPITAL FUNDING--PPL Capital Funding, Inc., a PPL financing subsidiary.
PPL ELECTRIC--PPL Electric Utilities Corporation, a regulated subsidiary of PPL
that transmits and distributes electricity in its service territory, and
provides electric supply to retail customers in this territory as a PLR.
PPL ENERGY FUNDING--PPL Energy Funding Corporation, which is a subsidiary of
PPL and the parent company of PPL Energy Supply.
PPL ENERGYPLUS - PPL EnergyPlus, LLC, a subsidiary of PPL Energy Supply, which
markets wholesale and retail electricity, and supplies energy and energy
services in newly deregulated markets.
PPL ENERGY SUPPLY--PPL Energy Supply, LLC, the parent company of PPL
Generation, PPL EnergyPlus, PPL Global and other subsidiaries. Formed in
November 2000, PPL Energy Supply is a subsidiary of PPL Energy Funding.
F-57
PPL GENERATION--PPL Generation, LLC, a subsidiary of PPL Energy Supply which,
effective July 1, 2000, owns and operates U.S. generating facilities through
various subsidiaries.
PPL GLOBAL--PPL Global, LLC, a subsidiary of PPL Energy Supply, which invests
in and develops domestic and international power projects, and owns and
operates international projects.
PPL MONTANA--PPL Montana, LLC, an indirect subsidiary of PPL Generation which
generates electricity for wholesale sales in Montana and the Northwest.
PPL MONTOUR--PPL Montour, LLC, a fossil generating subsidiary of PPL Generation.
PPL SERVICES--PPL Services Corporation, a subsidiary of PPL which provides
shared services for PPL and its subsidiaries.
PPL SUSQUEHANNA--PPL Susquehanna, LLC, the nuclear generating subsidiary of PPL
Generation.
PUC (Pennsylvania Public Utility Commission)-- state agency that regulates
certain ratemaking, services, accounting, and operations of Pennsylvania
utilities.
PUC FINAL ORDER--final order issued by the PUC on August 27, 1998, approving
the settlement of PPL Electric Utilities' restructuring proceeding.
PURPA (Public Utility Regulatory Policies Act of 1978)--legislation passed by
Congress to encourage energy conservation, efficient use of resources, and
equitable rates.
SCR--selective catalytic reduction.
SEC--Securities and Exchange Commission.
SFAS (Statement of Financial Accounting Standards)--accounting and financial
reporting rules issued by the FASB.
SNCR--selective non-catalytic reduction.
SO\\2\\--sulfur dioxide.
SWEB--the trading name for South Western Electricity plc, a British regional
electric utility company. Following the sale of its supply business in 1999,
SWEB was renamed Western Power Distribution. See WPD, below.
UF--Inflation-indexed peso denominated unit.
UGI--UGI Corporation.
WPD--Western Power Distribution (South West) plc, a British regional electric
utility company.
WPDH--WPD Holdings UK, a jointly owned subsidiary of PPL Global and Mirant.
WPDH owns WPD and Western Power Distribution (South Wales) plc.
WPDL--Western Power Distribution Limited, a wholly owned subsidiary of WPD
Investment Holdings Limited which is a jointly owned subsidiary of PPL Global
and Mirant. WPDL owns 100% of the common shares of Hyder.
F-58
PPL ENERGY SUPPLY: FINANCIAL STATEMENTS OF AFFILIATES
OVERVIEW OF FINANCIAL STATEMENTS OF AFFILIATES
Included in the Prospectus of PPL Energy Supply are financial statements of
two equity-method investees of PPL Global, LLC. PPL Global, LLC is one of the
predecessors of PPL Energy Supply, LLC. The investee financial statements are
being provided in accordance with Rule 3.05 and Rule 3.09 of Regulation S-X.
RULE 3.05
Tests were performed of businesses acquired during the period of the
financial statements of PPL Energy Supply, LLC provided herewith. This period
included the calendar years 1998, 1999 and 2000, and the interim nine-month
period ended September 30, 2001.
On September 29, 2000, Western Power Distribution Limited (WPDL), which is
jointly owned by PPL Global, LLC and a subsidiary of Mirant Corporation
(formerly Southern Energy Inc.), closed on the purchase of 110,156,041 shares
of Hyder plc (Hyder), for a total purchase price of 394,879,954 pounds sterling
($583,830,012 based on current exchange rates at that time). When combined with
WPDL's existing ownership interest in Hyder, this purchase gave WPDL
approximately 70% of Hyder's total outstanding shares. Subsequent to September
29, WPDL purchased the remaining shares of Hyder and is the owner of South
Wales Electricity plc, an electric distribution company serving approximately
1,000,000 customers in Wales. Hyder also owned Welsh Water and other
service-oriented businesses. Hyder completed the sale of its water business in
May 2001.
This acquisition met the full financial statement requirements under Rule
3.05 of Regulation S-X. The audited financial statements for the three years
ended March 31, 2000, the most recent year-end prior to the acquisition, are
included in this prospectus. These financial statements were also previously
filed by PPL Corporation, the previous parent of PPL Global, LLC and an SEC
registrant, by a Form 8-K filed on October 20, 2000.
RULE 3.09
Tests were also performed of unconsolidated investments of the predecessors
of PPL Energy Supply, LLC at December 31, 2000, 1999 and 1998.
PPL Global's equity investment in WPD Holdings UK (WPDH), in which it also
shares joint control with Mirant, met the tests for significance in each of
these periods.
Accordingly, the audited financial statements for the years ended March 31,
2001, 2000 and 1999 are included in this prospectus. These financial statements
are for SIUK plc, an indirect wholly-owned subsidiary of WPDH.
F-59
REPORT OF INDEPENDENT ACCOUNTANTS
AND FINANCIAL STATEMENTS OF
HYDER PLC
AS REQUIRED BY REGULATION S-X 210.3-05
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF
HYDER PLC
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of profit and loss account, cash flows, total
recognized gains and losses, and reconciliation of movements in shareholders'
funds, present fairly, in all material respects, the financial position of
Hyder plc and its subsidiaries at March 31, 2000 and March 31, 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended March 31, 2000, in conformity with accounting principles which
are generally accepted in the United Kingdom. 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 generally accepted
auditing standards in the United States and United Kingdom, 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 the opinion expressed above.
Accounting principles generally accepted in the United Kingdom vary in
certain significant respects from accounting principles generally accepted in
the United States. The application of the latter would have affected the
determination of consolidated net income expressed in British Pounds Sterling
for each of the three years in the period ended March 31, 2000 and the
determination of consolidated shareholders' equity and consolidated financial
position also expressed in British Pounds Sterling at March 31, 2000 and 1999
to the extent summarized in Note 45 to the consolidated financial statements.
PRICEWATERHOUSECOOPERS
Cardiff, United Kingdom
July 12, 2000, except for the contents of Note 45
which is as of August 18, 2000
F-60
HYDER PLC
PRINCIPAL ACCOUNTING POLICIES
The financial statements have been prepared in accordance with Accounting
Standards applicable in the United Kingdom and, except for the treatment of
investment properties and certain grants and customer contributions, comply
with the Companies Act 1985. An explanation of these departures from the
requirements of the Companies Act 1985 are given in the "Grants, customer
contributions and infrastructure charges" and "Investment properties" sections
below and notes 14(d) and 15, respectively. A summary of the principal group
accounting policies, which have been consistently applied, is shown below.
CHANGES IN PRESENTATION OF FINANCIAL INFORMATION
Since the previous directors' report and financial statements, the
Accounting Standards Board has issued Financial Reporting Standard (FRS)
16--Current tax. In addition the Urgent Issues Task Force (UITF) has issued a
number of abstracts in the year. FRS 15--Tangible fixed assets became mandatory
in respect of the year ended 31 March 2000. In preparing the accounts for the
year ended 31 March 1999, only the section of FRS 15 on infrastructure
maintenance accounting had been adopted. Where relevant these financial
statements comply with the new standards and UITF abstracts and have adopted in
full FRS 15. Where appropriate comparative figures have been restated.
BASIS OF ACCOUNTING
These financial statements have been prepared in accordance with the
historical cost convention, as modified by the inclusion of an external
professional valuation of the group's interest in certain investment properties.
BASIS OF CONSOLIDATION
The group financial statements comprise a consolidation of the financial
statements of Hyder plc and all its subsidiary undertakings and include the
group's share of the profits or losses and net assets of joint venture and
associated undertakings. The financial statements of the holding company and
each subsidiary company are prepared to 31 March. Uniform accounting policies
are adopted throughout the group.
ACQUISITIONS AND DISPOSALS
The results of companies and businesses acquired or disposed of during the
year are dealt with in the consolidated financial statements from the date of
acquisition or until the date of disposal. Where appropriate, adjustments are
made to bring different accounting policies of newly acquired companies into
line with the existing group accounting policies.
Goodwill arising from the purchase of subsidiary undertakings and
investments in associated undertakings prior to the introduction of FRS
10--Goodwill and intangible fixed assets, representing the excess of the fair
value of the purchase consideration (including costs of acquisition) over the
fair value of net assets acquired, was written off against consolidated
reserves in the year of acquisition. Goodwill, positive and negative, arising
on acquisitions after 1 April 1997 is treated in accordance with FRS 10 and,
where appropriate, is capitalised and amortised over its expected useful
economic life.
The profit or loss on the disposal of a previously acquired business is
derived after adjusting for the attributable amount of purchased goodwill
relating to that business not already charged to the profit and loss account.
F-61
TURNOVER
Turnover represents the income receivable in the ordinary course of business
for services provided and excludes value added tax.
JOINT VENTURES AND ASSOCIATED UNDERTAKINGS
The group's share of results of joint ventures and associated undertakings
is included in the consolidated financial statements based on the latest
audited accounts for each joint venture or associated undertaking and the
management accounts for the relevant period up to 31 March.
EXCEPTIONAL ITEMS
Exceptional items are those that need to be disclosed by virtue of their
size and incidence. Such items are included within operating profit unless they
represent profits or losses on the sale or termination of an operation, costs
of a fundamental reorganisation or restructuring having a material effect on
the nature and focus of the group, or profits or losses on the disposal of
fixed assets. In these cases, separate disclosure is provided on the face of
the profit and loss account after operating profit.
INTANGIBLE FIXED ASSETS
Intangible fixed assets are included at cost and are amortised over their
estimated useful economic lives.
TANGIBLE FIXED ASSETS AND DEPRECIATION
Tangible fixed assets comprise:
(i) water and sewerage infrastructure assets (being mains and sewers,
impounding and pumped raw water storage reservoirs, dams, sludge pipelines
and sea outfalls); and
(ii) other assets (including properties, overground water and sewerage
operational structures, electricity distribution networks, equipment and
fixtures and fittings).
WATER AND SEWERAGE INFRASTRUCTURE ASSETS
Infrastructure assets comprise a network of systems. Expenditure on
infrastructure assets relating to increases in capacity or enhancements of the
network and on maintaining the operating capability of the network in
accordance with defined standards of service, is treated as additions which are
included at cost after deducting grants and contributions.
The depreciation charge on infrastructure assets is the level of annual
expenditure required to maintain the operating capability of the network which
is based on the independently certified asset management plan.
OTHER ASSETS
Other assets are included at cost less accumulated depreciation. Freehold
land is not depreciated. Other assets are depreciated over their estimated
useful economic lives, which are principally as follows:
Freehold buildings.................................... 30-60 years
Leasehold properties.................................. over the period of the lease
Water and sewerage operational structures............. 40-80 years
Electricity distribution network assets............... 40 years
Fixed plant........................................... 20-40 years
Vehicles, mobile plant, equipment, computer hardware &
capitalised software................................ 3-10 years
F-62
Assets in the course of construction are not depreciated until commissioned.
Electricity distribution network assets are depreciated at 3% per year for
the first 20 years and 2% per year thereafter. All other assets are depreciated
evenly over their estimated economic life.
LEASED ASSETS
Where assets are financed by leasing arrangements which transfer
substantially all the risks and rewards of ownership of an asset to the lessee
(finance leases), the assets are treated as if they had been purchased and the
corresponding capital cost is shown as an obligation to the lessor. Leasing
payments are treated as consisting of a capital element and finance costs, the
capital element reducing the obligation to the lessor and the finance charges
being written off to the profit and loss account over the period of the lease
in reducing amounts in relation to the written down amount. The assets are
depreciated over the shorter of their estimated useful life and the lease
period. All other leases are regarded as operating leases. Rental costs arising
under operating leases are charged to the profit and loss account in the year
to which they relate.
Operating lease income receivable as lessor is recognised on a straight-line
basis over the term of the lease.
GRANTS, CUSTOMER CONTRIBUTIONS AND INFRASTRUCTURE CHARGES
Grants and customer contributions receivable relating to water and sewerage
infrastructure assets have been deducted from the cost of fixed assets. This is
not in accordance with the Companies Act 1985 which requires tangible fixed
assets to be shown at cost and hence grants and contributions as deferred
income. This departure from the requirements of the Companies Act 1985 is, in
the opinion of the directors, necessary for the financial statements to show a
true and fair view as while a provision is made for depreciation of
infrastructure assets, these assets do not have determinable finite lives and
therefore no basis exists on which to recognise grants and customer
contributions as deferred income. The effect of this treatment on the value of
tangible fixed assets is disclosed in note 14(d).
Grants and customer contributions in respect of expenditure on other fixed
assets are treated as deferred income and recognised in the profit and loss
account over the expected useful economic lives of the related assets.
Certain contributions noted above are wholly or partially refundable to
electricity customers if an agreed volume of electricity is distributed to
them. Such contributions are included in creditors until there is no further
liability to make refunds.
INVESTMENT PROPERTIES
In accordance with Statement of Standard Accounting Practice No. 19
"Accounting for Investment Properties", investment properties are included in
the balance sheet at open market value. Depreciation is not applied, except
where properties are held by the group on leasehold with an unexpired term of
20 years or less. This treatment departs from the general requirement of the
Companies Act 1985 to provide depreciation on any asset which has a limited
useful economic life. The directors consider that, as these properties are not
held for consumption but for investment, to depreciate them would not give a
true and fair view and thus it is necessary to adopt SSAP 19 in order to give a
true and fair view (note 15).
Profits and losses on the disposal of investment properties are calculated
as the difference between the net sale proceeds and the net carrying value in
the accounts (i.e. the value at the latest valuation). Any revaluation surplus
or deficiency held within a revaluation reserve relating to the asset disposed
of is released to profit and loss as a movement on reserves, and therefore does
not impact on the statement of recognised gains and losses.
F-63
INVESTMENTS
Long term investments held as fixed assets are stated at cost less amounts
written off or provided to reflect impairments in value. Those held as current
assets are stated at the lower of cost and net realisable value.
Long term investments in infrastructure projects are recognised at the total
committed amounts for equity and loan stock with outstanding commitments being
disclosed as amounts due to associated undertakings and joint ventures.
STOCKS AND WORK IN PROGRESS
Stocks are stated at the lower of cost and net realisable value which takes
account of any provision necessary to recognise damage and obsolescence. Work
in progress is valued at the lower of cost and net realisable value. Cost
includes labour, materials, transport and directly attributable overheads.
AMOUNTS RECOVERABLE ON LONG TERM CONTRACTS
Amounts recoverable on long term contracts represent work undertaken but not
yet invoiced to customers. These amounts, which are included in debtors, are
stated at cost plus attributable profit, to the extent that such profit is
reasonably certain and after making provision for any foreseeable losses in
completing contracts, less payments on account. For this purpose, cost
comprises the direct costs of providing the service, together with directly
attributable overheads.
PENSION COSTS
Contributions are charged to the profit and loss account so as to spread the
cost of pensions over employees' working lives with the group. Contribution
rates are based on the advice of a professionally qualified actuary. Any
difference between the charge to the profit and loss account and contributions
paid is shown as an asset or liability in the balance sheet.
FOREIGN CURRENCIES
On consolidation, balance sheets and profit and loss accounts of subsidiary
undertakings are translated into sterling at closing rates of exchange.
Exchange differences resulting from the translation at closing rates of net
investments in subsidiary and associated undertakings are dealt with in the
statement of total recognised gains and losses.
Fixed asset investments denominated in foreign currencies which are hedged
by related currency borrowings are translated into sterling at the rate of
exchange ruling at the end of the financial year. The gains or losses arising
from the retranslation of these investments at each year end are offset against
those gains and losses arising on the retranslation of the related foreign
exchange borrowings. Those fixed asset investments which are not hedged by
related foreign currency borrowings are translated into sterling at the rate of
exchange ruling at the date of acquisition.
All other exchange gains or losses on settlement or translation at closing
rates of exchange of monetary assets and liabilities are included in the
determination of profit for the year.
FINANCIAL INSTRUMENTS
Derivative instruments utilised by the group are currency swaps, currency
forward exchange contracts, and interest rate swaps. Derivative instruments are
used for hedging purposes to alter the risk profile of existing underlying
exposures within the group. Currency swap agreements and currency forward
exchange contracts are translated at the rates ruling in the agreements and
contracts.
F-64
Interest differentials, under interest swap arrangements used to manage
interest rate exposure on borrowings and current asset investments, are
recognised by adjusting interest payable or receivable as appropriate.
RESEARCH AND DEVELOPMENT
Research and development expenditure is charged to the profit and loss
account in the year in which it is incurred.
DEFERRED TAXATION
Provision is made for deferred taxation, using the liability method, on all
material timing differences to the extent that it is probable that a liability
or asset will crystallise.
QUALIFYING EMPLOYEE SHARE OPTION TRUST (QUEST)
The consolidated accounts include the shares in the company held by the
group's Quest (note 30(c)). The shares held are included as fixed asset
investments and are stated at cost less amounts provided to reflect impairment
in value. Under the rules of the Quest dividends have been waived by the
trustee. The expenses of the Quest which are borne by the group are expensed as
incurred.
LONG TERM INCENTIVE PLAN (L-TIP)
The consolidated accounts include the shares in the company held by the
group's L-Tip (note 30(b)). Whilst the L-Tips are capable of vesting to the
directors the cost of the ordinary shares are written off against profits over
the three year performance period to which the conditional allocation relates.
The cost of shares which have lapsed under the L-Tip criteria are credited to
profits. The shares held are included in fixed assets investments and are
stated at cost less amounts provided to reflect impairment in value.
F-65
HYDER PLC
CONSOLIDATED PROFIT AND LOSS ACCOUNTS
FOR THE YEARS ENDED 31 MARCH
NOTE 2000 1999 RESTATED 1998 RESTATED
---- -------- ------------- -------------
LM LM LM
TURNOVER:
Group and share of joint ventures--continuing operations................. 810.8 709.7 664.3
Less: share of joint ventures............................................ (30.9) (7.9) (6.9)
-------- ------- -------
Group turnover--continuing operations.................................... 779.9 701.8 657.4
Group turnover--discontinued operations.................................. 506.0 592.6 527.7
-------- ------- -------
Group turnover........................................................... 2&3 1,285.9 1,294.4 1,185.1
-------- ------- -------
NET OPERATING COSTS:..................................................... 4
Continuing operations.................................................... (615.8) (431.2) (417.8)
Discontinued operations.................................................. (509.7) (566.6) (522.6)
-------- ------- -------
(1,125.5) (997.8) (940.4)
-------- ------- -------
GROUP OPERATING PROFIT:
Continuing operations.................................................... 164.1 270.6 239.6
Discontinued operations.................................................. (3.7) 26.0 5.1
-------- ------- -------
160.4 296.6 244.7
-------- ------- -------
GROUP OPERATING PROFIT BEFORE EXCEPTIONAL ITEMS:
Continuing operations.................................................... 274.8 270.6 279.6
Discontinued operations.................................................. 14.2 26.0 5.1
-------- ------- -------
289.0 296.6 284.7
EXCEPTIONAL ITEMS:....................................................... 5
Continuing operations.................................................... (110.7) -- (40.0)
Discontinued operations.................................................. (17.9) -- --
-------- ------- -------
(128.6) -- (40.0)
-------- ------- -------
GROUP OPERATING PROFIT AFTER EXCEPTIONAL ITEMS:
Continuing operations.................................................... 164.1 270.6 239.6
Discontinued operations.................................................. (3.7) 26.0 5.1
-------- ------- -------
160.4 296.6 244.7
-------- ------- -------
SHARE OF OPERATING PROFIT IN:
Joint ventures--continuing operations.................................... 6.0 2.6 2.6
Associates--continuing operations........................................ 0.8 1.9 1.8
-------- ------- -------
167.2 301.1 249.1
TOTAL OPERATING PROFIT--GROUP AND SHARE OF JOINT VENTURES AND ASSOCIATES:
Continuing operations.................................................... 170.9 275.1 244.0
Discontinued operations.................................................. (3.7) 26.0 5.1
-------- ------- -------
167.2 301.1 249.1
Group income from investments-continuing operations...................... 7 3.5 9.9 9.3
Profit on disposal of interests in investments........................... 8 5.7 18.6 5.5
Profit on disposal of group operations................................... 39 47.0 -- --
-------- ------- -------
Profit on ordinary activities before interest............................ 223.4 329.6 263.9
Interest receivable...................................................... 24.2 20.5 17.8
INTEREST PAYABLE:
Group.................................................................... 9 (166.3) (143.4) (113.5)
Joint ventures........................................................... (4.6) (0.7) --
-------- ------- -------
Profit on ordinary activities before taxation............................ 76.7 206.0 168.2
Ordinary taxation........................................................ 10(a) (1.9) (8.6) (13.6)
-------- ------- -------
Profit on ordinary activities after ordinary taxation.................... 74.8 197.4 154.6
Exceptional taxation--windfall tax....................................... 10(b) -- -- (281.9)
-------- ------- -------
Profit/(loss) on ordinary activities after taxation...................... 74.8 197.4 (127.3)
Equity minority interests................................................ (0.2) -- --
Dividends on preference shares and appropriations........................ 11 (16.4) (16.4) (16.4)
-------- ------- -------
Profit/(loss) attributable to ordinary shareholders...................... 58.2 181.0 (143.7)
Dividends on ordinary shares............................................. 11 (10.1) (74.5) (73.3)
-------- ------- -------
Retained profit/(loss) for the year...................................... 32 48.1 106.5 (217.0)
======== ======= =======
EARNINGS/(LOSS) PER ORDINARY SHARE:
--Basic............................................................... 12 39.0p 123.4p (99.8)p
--Diluted............................................................. 12 39.0p 122.5p (98.4)p
EARNINGS PER ORDINARY SHARE BEFORE EXCEPTIONAL ITEMS, PROFIT ON DISPOSAL
OF GROUP OPERATIONS AND WINDFALL TAX:
--Basic............................................................... 12 97.2p 123.4p 122.7p
--Diluted............................................................. 12 97.1p 122.5p 120.9p
======== ======= =======
Dividends per ordinary share............................................. 11 6.7p 50.4p 50.4p
======== ======= =======
F-66
HYDER PLC
BALANCE SHEETS AT 31 MARCH 2000
GROUP COMPANY
------------------ ------------------
NOTE 2000 1999 2000 1999
---- -------- -------- -------- --------
LM LM LM LM
FIXED ASSETS:
Intangible assets...................................... 13 3.5 3.8 -- --
Tangible assets........................................ 14 2,951.1 2,832.4 2.2 2.4
Investment properties.................................. 15 10.9 9.4 -- --
Investments in:........................................ 16
Joint ventures:.....................................
Share of gross assets........................... 217.2 150.2 -- --
Share of gross liabilities...................... (179.4) (129.8) -- --
37.8 20.4 -- --
Associates.......................................... 10.4 9.8 -- --
Others.............................................. 52.2 62.1 1,536.5 1,548.6
Own shares.......................................... 10.3 21.7 10.3 21.7
-------- -------- -------- --------
3,076.2 2,959.6 1,549.0 1,572.7
-------- -------- -------- --------
CURRENT ASSETS:
Stocks and work in progress............................ 17 16.9 16.0 -- --
Debtors................................................ 18 238.0 314.2 364.5 423.4
Current asset investments.............................. 19 433.3 591.3 354.7 464.4
Cash at bank and in hand............................... 34.0 21.0 0.3 0.4
-------- -------- -------- --------
722.2 942.5 719.5 888.2
CURRENT LIABILITIES:
Creditors: amounts falling due within one year......... 20(a) (363.6) (556.3) (113.3) (177.4)
-------- -------- -------- --------
Net current assets..................................... 358.6 386.2 606.2 710.8
-------- -------- -------- --------
Total assets less current liabilities.................. 3,434.8 3,345.8 2,155.2 2,283.5
-------- -------- -------- --------
Creditors: amounts falling due after more than one year 20(b) (2,143.5) (2,147.0) (1,304.9) (1,302.2)
Provisions for liabilities and charges................. 27 (79.9) (143.1) (2.4) (2.4)
Accruals and deferred income........................... 28 (159.8) (155.3) -- --
-------- -------- -------- --------
Net assets............................................. 1,051.6 900.4 847.9 978.9
======== ======== ======== ========
CAPITAL AND RESERVES:
Called up share capital................................ 29 392.8 388.4 392.8 388.4
Share premium account.................................. 31 133.0 137.4 133.0 137.4
Reserves............................................... 32 525.1 372.0 322.1 453.1
Equity shareholders' funds............................. 844.3 691.2 641.3 772.3
Non-equity shareholders' funds......................... 206.6 206.6 206.6 206.6
Total shareholders' funds.............................. 1,050.9 897.8 847.9 978.9
Equity minority interests.............................. 33 0.7 2.6 -- --
-------- -------- -------- --------
1,051.6 900.4 847.9 978.9
======== ======== ======== ========
The financial statements above pages were approved by the Board of directors
on 12 July 2000 and were signed on its behalf by:
J V H ROBINS P J TWAMLEY
Chairman Group Finance Director
F-67
HYDER PLC
CONSOLIDATED CASH FLOW STATEMENTS
FOR THE YEARS ENDED 31 MARCH
NOTE 2000 1999 1998
---- ------ ------ ------
LM LM LM
NET CASH INFLOW FROM OPERATING ACTIVITIES:
--Continuing operations........................................ 34 368.7 382.5 318.6
--Discontinued operations...................................... 34 7.9 1.3 6.4
------ ------ ------
376.6 383.8 325.0
====== ====== ======
Dividends received from joint ventures and associated undertakings 0.7 -- 0.9
====== ====== ======
RETURNS ON INVESTMENTS AND SERVICING OF FINANCE:
Interest received................................................. 22.9 14.5 19.8
Interest paid..................................................... (144.8) (115.5) (96.0)
Preference dividend paid.......................................... (16.4) (16.4) (16.3)
Interest element of finance lease rental payments................. (16.2) (9.7) (3.9)
Dividends received and other investment income.................... 3.5 12.8 12.3
------ ------ ------
(151.0) (114.3) (84.1)
====== ====== ======
TAXATION:
UK corporation tax paid........................................... (0.9) (15.5) (21.8)
Windfall tax paid................................................. -- (141.0) (140.9)
Overseas tax (paid)/repaid........................................ (1.1) (0.2) 0.1
------ ------ ------
(2.0) (156.7) (162.6)
====== ====== ======
CAPITAL EXPENDITURE AND FINANCIAL INVESTMENT:
Sale of intangible fixed assets................................... 0.4 -- --
Purchase of tangible fixed assets................................. (353.1) (447.4) (412.3)
Sale of tangible fixed assets..................................... 4.7 5.5 5.3
Purchase of fixed asset investments............................... (1.7) (5.7) (0.4)
Sale of fixed asset investments................................... 12.5 61.3 6.7
Grants and contributions received................................. 14.3 19.0 29.4
------ ------ ------
(322.9) (367.3) (371.3)
====== ====== ======
ACQUISITIONS AND DISPOSALS:
Purchase of additional interest in subsidiary undertakings........ 38 (1.5) (4.3) --
Net cash acquired with subsidiaries............................... -- 1.9 --
Investments in joint ventures and associated undertakings......... (3.9) (11.9) (6.8)
Sale of group operations.......................................... 39 103.9 -- --
------ ------ ------
98.5 (14.3) (6.8)
====== ====== ======
Equity dividends paid............................................. (98.4) (18.5) (32.0)
------ ------ ------
Cash outflow before use of liquid resources and financing......... (98.5) (287.3) (330.9)
====== ====== ======
MANAGEMENT OF LIQUID RESOURCES:...................................
Purchase of commercial paper...................................... (323.0) (467.0) (569.9)
Sale of commercial paper.......................................... 412.0 446.5 538.6
Net decrease/(increase) in deposits............................... 73.0 (269.2) (1.1)
------ ------ ------
162.0 (289.7) (32.4)
====== ====== ======
FINANCING:
Issue of ordinary shares.......................................... 36 -- 0.5 4.9
New loans, finance leases and bonds............................... 2.0 621.5 482.8
Expenses of issuing bonds......................................... 36 -- (6.6) (3.5)
Loan repayments................................................... 36 (57.5) (9.0) (150.1)
Capital element of finance lease rental payments.................. 36 (0.2) (0.5) (0.5)
------ ------ ------
(55.7) 605.9 333.6
====== ====== ======
Increase/(decrease) in cash in the year........................... 37 7.8 28.9 (29.7)
====== ====== ======
F-68
HYDER PLC
STATEMENT OF TOTAL RECOGNISED GAINS AND LOSSES FOR THE YEARS ENDED MARCH
2000 1999 1998
---- ----- ------
LM LM LM
Profit/(loss) for the financial year attributable to ordinary shareholders 58.2 181.0 (143.7)
Currency translation differences on foreign currency net investments...... (1.3) 0.2 (3.2)
Surplus on revaluation of investment properties........................... 1.5 1.0 (0.2)
---- ----- ------
Total recognised gains/(losses) for the year........................... 58.4 182.2 (147.1)
==== ===== ======
RECONCILIATION OF MOVEMENTS IN SHAREHOLDERS' FUNDS FOR THE
YEARS ENDED 31 MARCH
2000 1999 1998
------- ----- ------
LM LM LM
Total recognised gains/(losses) for the year........................................ 58.4 182.2 (147.1)
Ordinary dividends.................................................................. (10.1) (74.5) (73.3)
New ordinary share capital issued................................................... 4.4 2.0 7.5
Premium on ordinary share capital issued............................................ -- 0.4 39.5
Scrip dividend issued in lieu of cash dividend...................................... 21.5 14.6 14.9
Utilisation of share premium account for the nominal value of ordinary shares issued
under the scrip dividend.......................................................... (4.4) (1.9) (1.5)
Goodwill written off................................................................ -- -- (0.3)
Goodwill written back on disposal................................................... 84.0 2.0 --
Charge to reserves arising on issue of shares to qualifying employee share ownership
trust............................................................................. -- -- (18.7)
Adjustment to reserves on increased shareholding in subsidiary...................... (0.7) (0.5) --
------- ----- ------
Net increase in shareholders' funds................................................. 153.1 124.3 (179.0)
At 1 April.......................................................................... 897.8 773.5 952.5
------- ----- ------
At 31 March......................................................................... 1,050.9 897.8 773.5
======= ===== ======
There is no material difference between the results disclosed in the profit
and loss account and the results on an unmodified historical cost basis.
F-69
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS
1. COMPANY PROFIT AND LOSS ACCOUNT
As permitted by section 230 of the Companies Act 1985, the profit and loss
account of the company has not been included in these financial statements. The
loss after taxation for the year dealt with in the financial statements of the
company was L125.8m (1999 profit of L74.7m; 1998 profit of L298.1m).
2. SEGMENTAL ANALYSIS BY CLASS OF BUSINESS
(A) TURNOVER
INTRA INTER
TOTAL SEGMENT SEGMENT EXTERNAL
TURNOVER TURNOVER TURNOVER TURNOVER
-------- -------- -------- --------
LM LM LM LM
YEAR ENDED 31 MARCH 2000:
Continuing operations:
Regulated water and sewerage activities....... 472.7 -- 1.5 471.2
Regulated electricity distribution activities. 199.1 -- 124.2 74.9
Infrastructure activities:
-- Group..................................... 237.3 2.1 28.9 206.3
-- Joint ventures............................ 30.9 -- -- 30.9
Managed services activities................... 164.0 6.0 136.2 21.8
Other activities.............................. 21.6 -- 15.9 5.7
------- --- ----- -------
1,125.6 8.1 306.7 810.8
Discontinued operations:.........................
Energy supply activities...................... 501.9 -- 6.0 495.9
Infrastructure activities..................... 10.1 -- -- 10.1
------- --- ----- -------
1,637.6 8.1 312.7 1,316.8
======= === ===== =======
Total:
-- Group..................................... 1,606.7 8.1 312.7 1,285.9
-- Joint ventures............................ 30.9 -- -- 30.9
======= === ===== =======
YEAR ENDED 31 MARCH 1999:
Continuing operations:
Regulated water and sewerage activities....... 456.0 -- 1.5 454.5
Regulated electricity distribution activities. 195.4 -- 153.3 42.1
Infrastructure activities:
-- Group..................................... 225.8 4.6 33.4 187.8
-- Joint ventures............................ 7.9 -- -- 7.9
Managed services activities................... 176.1 4.4 162.1 9.6
Other activities.............................. 10.7 -- 2.9 7.8
------- --- ----- -------
1,071.9 9.0 353.2 709.7
F-70
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
INTRA INTER
TOTAL SEGMENT SEGMENT EXTERNAL
TURNOVER TURNOVER TURNOVER TURNOVER
-------- -------- -------- --------
LM LM LM LM
DISCONTINUED OPERATIONS:
Energy supply activities........................ 588.9 -- 6.7 582.2
Infrastructure activities....................... 10.4 -- -- 10.4
------- ---- ----- -------
1,671.2 9.0 359.9 1,302.3
======= ==== ===== =======
TOTAL:
-- Group........................................ 1,663.3 9.0 359.9 1,294.4
-- Joint ventures............................... 7.9 -- -- 7.9
======= ==== ===== =======
YEAR ENDED 31 MARCH 1998:
CONTINUING OPERATIONS:
Regulated water and sewerage activities......... 440.7 -- 1.2 439.5
Regulated electricity distribution activities... 190.4 -- 146.6 43.8
INFRASTRUCTURE ACTIVITIES
-- Group...................................... 200.2 1.2 35.1 163.9
-- Joint ventures............................. 6.9 -- -- 6.9
MANAGED SERVICES ACTIVITIES..................... 145.4 12.7 126.7 6.0
OTHER ACTIVITIES................................ 4.3 -- 0.1 4.2
------- ---- ----- -------
987.9 13.9 309.7 664.3
DISCONTINUED OPERATIONS:
ENERGY SUPPLY ACTIVITIES........................ 534.2 -- 17.5 516.7
INFRASTRUCTURE ACTIVITIES....................... 11.0 -- -- 11.0
------- ---- ----- -------
1,533.1 13.9 327.2 1,192.0
======= ==== ===== =======
TOTAL:
-- Group........................................ 1,526.2 13.9 327.2 1,185.1
-- Joint ventures............................... 6.9 -- -- 6.9
======= ==== ===== =======
Turnover is derived from the following sources:
- External: transactions between group companies and external customers.
- Intra segment: transactions between group companies trading within the
same segment.
- Inter segment: transactions between group companies trading in different
segments.
F-71
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(B) PROFIT ON ORDINARY ACTIVITIES BEFORE TAXATION
2000 2000 1998 1998
BEFORE EXCEPTIONAL 1999 BEFORE EXCEPTIONAL 1998
EXCEPTIONAL ITEMS 2000 RESTATED EXCEPTIONAL ITEMS RESTATED
ITEMS (NOTE 5) TOTAL TOTAL ITEMS (NOTE 5) TOTAL
----------- ----------- ------ -------- ----------- ----------- --------
LM LM LM LM LM LM LM
CONTINUING OPERATIONS:
Regulated water and sewerage
activities....................... 186.0 (34.1) 151.9 166.6 178.3 (28.0) 150.3
Regulated electricity distribution
activities....................... 87.5 (60.7) 26.8 96.0 86.1 (9.0) 77.1
Infrastructure activities......... 11.4 (4.4) 7.0 24.8 20.2 (5.2) 15.0
Managed services activities....... 6.7 (1.0) 5.7 22.2 21.9 3.3 25.2
Other activities.................. 5.1 -- 5.1 5.4 4.5 -- 4.5
----- ------ ------ ------ ----- ----- -----
296.7 (100.2) 196.5 315.0 311.0 (38.9) 272.1
DISCONTINUED OPERATIONS:
Energy supply activities.......... 14.9 (17.9) (3.0) 26.3 4.2 -- 4.2
Infrastructure activities......... (0.7) -- (0.7) (0.3) 0.9 -- 0.9
----- ------ ------ ------ ----- ----- -----
310.9 (118.1) 192.8 341.0 316.1 (38.9) 277.2
Business development costs and
corporate overheads.............. (3.9) (10.5) (14.4) (7.6) (8.6) (1.1) (9.7)
Elimination of intercompany
operating profit capitalised..... (2.0) -- (2.0) (3.8) (3.6) -- (3.6)
Profit on disposal of group
operations....................... 47.0 -- 47.0 -- -- --
----- ------ ------ ------ ----- ----- -----
Profit before interest............ 352.0 (128.6) 223.4 329.6 303.9 (40.0) 263.9
===== ====== ===== =====
Net interest payable.............. (146.7) (123.6) (95.7)
------ ------ -----
Profit before taxation............ 76.7 206.0 168.2
====== ====== =====
Infrastructure activities and Other activities include L9.2m (1999 L28.5m;
1998 L14.8m) in respect of income from investments (including profit on
disposal of investments) (notes 7 and 8 below) and L6.8m (1999 L4.5m; 1998
L4.4m) in respect of share of operating profit of joint ventures and associates
as this reflects the management control of those investments.
F-72
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(C) NET ASSETS
2000 1999 1998
-------- -------- --------
LM LM LM
CONTINUING OPERATIONS:
Regulated water and sewerage activities.................... 1,991.3 1,825.9 1,643.2
Regulated electricity distribution activities.............. 505.2 471.7 403.4
Regulated electricity distribution activities--windfall tax -- -- (44.8)
Infrastructure activities.................................. 146.9 152.8 154.1
Managed services activities................................ 67.2 81.1 58.3
Other activities........................................... 15.1 (44.0) (5.9)
Other activities--windfall tax............................. -- -- (96.2)
-------- -------- --------
2,725.7 2,487.5 2,112.1
DISCONTINUED OPERATIONS:
Energy supply activities................................... -- (19.6) (61.6)
Infrastructure activities.................................. -- 6.6 5.2
-------- -------- --------
2,725.7 2,474.5 2,055.7
Net debt................................................ (1,674.1) (1,574.1) (1,282.2)
-------- -------- --------
1,051.6 900.4 773.5
======== ======== ========
Infrastructure activities includes L48.2m (1999 L30.2m; 1998 L29.6m) in
respect of share of net assets of joint ventures and associates as this
reflects the management control of those investments.
3. SEGMENTAL ANALYSIS BY GEOGRAPHICAL AREA BY DESTINATION
(A) TURNOVER
2000 1999 1998
------- ------- -------
LM LM LM
United Kingdom and Europe:
--Group................ 1,223.6 1,223.7 1,120.7
--Joint ventures....... 30.9 7.9 6.9
Asia Pacific.............. 38.2 48.5 38.7
Rest of the World......... 24.1 22.2 25.7
------- ------- -------
Total:
--Group................ 1,285.9 1,294.4 1,185.1
--Joint ventures....... 30.9 7.9 6.9
======= ======= =======
Included in United Kingdom and Europe turnover by destination is turnover of
L506.0m (1999 L592.6m; 1998 L527.7m) relating to the discontinued energy supply
and infrastructure activities.
F-73
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(B) PROFIT/(LOSS) ON ORDINARY ACTIVITIES BEFORE TAXATION
1999 1998
2000 RESTATED RESTATED
------ -------- --------
LM LM LM
United Kingdom and Europe............................... 195.0 339.2 277.7
Asia Pacific............................................ (3.4) 0.6 (2.5)
Rest of the World....................................... 1.2 1.2 2.0
------ ------ -----
192.8 341.0 277.2
Business development costs and corporate overheads...... (14.4) (7.6) (9.7)
Elimination of intercompany operating profit capitalised (2.0) (3.8) (3.6)
Profit on disposal of group operations.................. 47.0 -- --
------ ------ -----
Profit before interest.................................. 223.4 329.6 263.9
Net interest payable.................................... (146.7) (123.6) (95.7)
------ ------ -----
Profit before taxation.................................. 76.7 206.0 168.2
====== ====== =====
United Kingdom and Europe include L9.2m (1999 L28.5m; 1998 L14.8m) in
respect of income from investments (including profit on disposal of
investments) (notes 7 and 8 below) and L6.8m (1999 L4.5m; 1998 L4.4m) in
respect of share of operating profit of joint ventures and associates as this
reflects the management control of those investments.
(C) NET ASSETS
2000 1999 1998
-------- -------- --------
LM LM LM
United Kingdom and Europe 2,690.1 2,450.4 2,035.0
Asia Pacific............. 7.0 4.6 8.4
Rest of the World........ 27.1 19.5 12.3
-------- -------- --------
2,724.2 2,474.5 2,055.7
Net debt (note 35(b)).... (1,674.1) (1,574.1) (1,282.2)
-------- -------- --------
1,050.1 900.4 773.5
======== ======== ========
United Kingdom and Europe includes L48.2m (1999 L30.2m; 1998 L29.6m) in
respect of share of net assets of joint ventures and associates as this
reflects the management control of those investments. Turnover and profit
before taxation by origin are not materially different from that by destination.
F-74
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
4. NET OPERATING COSTS
2000 2000 1998 1998
BEFORE EXCEPTIONAL BEFORE EXCEPTIONAL
EXCEPTIONAL ITEMS 2000 1999 EXCEPTIONAL ITEMS 1998
NOTE ITEMS (NOTE 5) TOTAL TOTAL ITEMS (NOTE 5) TOTAL
---- ----------- ----------- ------- ----- ----------- ----------- -----
LM LM LM LM LM LM LM
CONTINUING OPERATIONS:
Change in stocks and work in progress...... (0.6) -- (0.6) (1.9) (0.6) -- (0.6)
Staff costs................................ 6(b) 253.5 -- 253.5 236.4 224.7 -- 224.7
Severance and redundancy costs............. -- 21.9 21.9 2.0 -- 25.0 25.0
DEPRECIATION:
--Own assets............................ 126.5 -- 126.5 117.8 100.4 -- 100.4
--Assets held under finance leases...... 10.3 -- 10.3 5.0 4.9 -- 4.9
Amounts written off fixed assets........... -- 51.0 51.0 7.1 0.1 1.5 1.6
Amounts written off fixed asset investments 1.1 -- 1.1 2.0 1.4 -- 1.4
Amounts written off own shares............. -- 10.0 10.0 -- -- -- --
Research and development................... 0.7 -- 0.7 0.7 1.3 -- 1.3
RENTALS UNDER OPERATING LEASES:
--Hire of plant and equipment........... 9.0 -- 9.0 1.3 1.3 -- 1.3
--Other................................. 5.0 -- 5.0 3.2 6.1 -- 6.1
FEES PAID TO AUDITORS:
--Audit services........................ 0.7 -- 0.7 0.7 0.7 -- 0.7
--Taxation services..................... 0.1 -- 0.1 0.1 0.2 -- 0.2
--Consultancy services.................. -- 1.4 1.4 0.1 0.1 -- 0.1
--Other services........................ 0.4 -- 0.4 -- 0.4 -- 0.4
Year 2000 costs............................ 2.8 -- 2.8 7.0 1.5 -- 1.5
Other operating charges.................... 178.1 26.4 204.5 132.3 117.0 13.5 130.5
Amortisation of grants and contributions... (6.0) -- (6.0) (5.9) (5.5) -- (5.5)
Loss/(profit) on disposal of fixed assets.. 0.5 -- 0.5 -- (0.8) -- (0.8)
Own work capitalised....................... (74.7) -- (74.7) (76.0) (75.0) -- (75.0)
Net rents receivable....................... (2.3) -- (2.3) (0.7) (0.4) -- (0.4)
----- ----- ------- ----- ----- ---- -----
Net continuing operating costs............. 505.1 110.7 615.8 431.2 377.8 40.0 417.8
----- ----- ------- ----- ----- ---- -----
DISCONTINUED OPERATIONS:
Change in stocks and work in progress...... (0.3) -- (0.3) -- -- -- --
Staff costs................................ 6(b) 9.2 -- 9.2 9.3 7.2 -- 7.2
Severance and redundancy costs............. -- 0.5 0.5 -- -- -- --
DEPRECIATION:
--Own assets............................ 3.6 -- 3.6 1.6 0.9 -- 0.9
Amounts written off fixed assets........... -- 16.3 16.3 -- -- -- --
Research and development................... 0.2 -- 0.2 0.1 0.1 -- 0.1
Rentals under operating leases:............
--Other................................. -- -- -- 0.5 0.4 -- 0.4
FEES PAID TO AUDITORS:
--Consultancy services.................. -- 0.1 0.1 0.4 -- -- --
Year 2000 costs............................ 0.1 -- 0.1 1.7 0.6 -- 0.6
Energy purchases........................... 287.1 -- 287.1 329.6 305.3 -- 305.3
Power purchase provision................... (6.4) -- (6.4) (7.3) -- -- --
Other operating charges.................... 198.3 1.0 199.3 230.7 208.1 -- 208.1
----- ----- ------- ----- ----- ---- -----
Net discontinued operating costs........... 491.8 17.9 509.7 566.6 522.6 -- 522.6
----- ----- ------- ----- ----- ---- -----
Total operating costs...................... 996.9 128.6 1,125.5 997.8 900.4 40.0 940.4
===== ===== ======= ===== ===== ==== =====
F-75
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Other fees paid to the auditors and capitalised were L91,500 (1999 L104,000;
1998 Lnil). Included in audit services is L9,250 (1999 L9,000; 1998 L8,650) in
respect of audit fees incurred by the company.
Fees of L7,000 and L44,000 were paid to the auditors in 2000 for services
provided in respect of the disposal of the investment in UK Data Collection
Services Limited and the energy supply business respectively. These costs have
been deducted in arriving at the profit on disposal.
5. EXCEPTIONAL ITEMS
2000 1999 1998
----- ---- ----
LM LM LM
CONTINUING OPERATIONS:
Restructuring costs:
Regulated water and sewerage activities............ 14.1 -- 25.8
Regulated electricity distribution activities...... 12.7 -- 8.8
Infrastructure activities.......................... 2.8 -- 1.2
Managed services activities........................ 4.5 -- --
Other activities................................... -- -- 2.0
Business development costs and corporate overheads. 0.5 -- 0.4
----- -- ----
34.6 -- 38.2
Restructuring credits:
Regulated electricity distribution activities...... (6.7) -- --
Managed services activities........................ (3.5) -- (3.3)
----- -- ----
24.4 -- (3.3)
Computer system development costs:
Regulated electricity distribution services........ 54.7 -- --
AMOUNTS WRITTEN OFF OWN SHARES:
Business development costs and corporate overheads.... 10.0 -- --
BAD AND DOUBTFUL DEBT PROVISIONS:
Regulated water and sewerage activities............... 20.0 -- --
LEASEHOLD PROPERTY PROVISIONS:
Regulated water and sewerage activities............... -- -- 2.2
Regulated electricity distribution activities......... -- -- 0.2
Business development costs and corporate overheads.... -- -- 0.7
Infrastructure activities............................. 1.6 -- 2.0
----- -- ----
1.6 -- 5.1
----- -- ----
110.7 -- 40.0
----- -- ----
DISCONTINUED OPERATIONS:
Restructuring costs:
Energy supply activities........................... 0.5 -- --
Computer systems development costs:
Energy supply activities........................... 17.4 -- --
----- -- ----
17.9 -- --
----- -- ----
128.6 -- 40.0
===== == ====
The tax credit attributable to these exceptional items is L9.7m (1999 Lnil;
1998 L1.6m).
F-76
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Restructuring costs of L35.1m (1999 Lnil; 1998 L38.2m) principally relate to
job reductions in the regulated water and electricity distribution businesses.
Surplus provisions of L10.2m (1999 Lnil; 1998 L3.3m) relating to prior year
manpower reduction programmes were released after reappraisal of obligations
and were offset against the L35.1m (1999 Lnil; 1998 L38.3m) charge in the year.
Computer system development costs written off amounting to L43.5m related to
the cancellation of a new utility billing system which did not meet the needs
of the rapidly developing and sophisticated multi purpose product offerings.
Computer system development costs of L24.1m were also written off following
the electricity distribution price review whereby the costs of systems
developed before the opening of the electricity competitive market were not
remunerated by the regulator. The carrying value of these computer systems were
written down to L8.8m. Costs of L4.5m relating to new electricity metering
obligations, effective from April 2000, have also been charged as an
exceptional item.
The bad and doubtful debt provision of L20m arose from a reassessment of our
ability to collect domestic water and sewerage debt following the Government's
decision to ban disconnection of domestic water supplies, combined with the
ruling on the watercard and the High Court decision that the "Two in One"
budget scheme was not authorised under the Electricity Act.
The write down of own shares of L10.0m reflects the reduction of in value of
Hyder shares held by the company under the Qualifying employee share option
schemes and the directors' long term incentive scheme.
Property provisions of L1.6m (1999 Lnil; 1998 L5.1m) related to the
directors' assessment of the future cost of unoccupied leasehold properties and
amounts written off freehold properties.
6. DIRECTORS AND EMPLOYEES
DIRECTORS' EMOLUMENTS AND INTERESTS
(A) STATEMENT OF COMPLIANCE
Throughout the year the company complied with Schedule A and has given full
consideration to Schedule B of the Best Practice Provisions on Remuneration
committees as annexed to the Financial Services Authority Listing Rules.
(B) REMUNERATION COMMITTEE
The committee consists of the non-executive directors, other than the Group
Chairman, under the chairmanship of D G Hawkins. None of the committee has any
personal financial interests in the group (other than as a shareholder or
bondholder), has any conflict of interests arising from cross-directorships or
otherwise, or has day-to-day involvement in running the business. The committee
consults the Group Chairman and the Group Chief Executive about its proposals
and the performance of executive directors and has access to professional
advice from inside and outside the company.
(C) NON-EXECUTIVE DIRECTORS
The remuneration of the non-executive directors is determined by the Board
within the limits set out in the Articles of Association and based upon
independent advice in respect of fees paid to non-executive directors of
similar companies.
Since his appointment as Group Chairman in 1998 J V H Robins has been paid
fees at the rate of L125,000 per annum.
F-77
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
The fee paid to each non-executive director, excluding the chairman, was
L28,000 (1999 L28,000). Non-executive directors cannot participate in any of
the company's share option or incentive schemes and are not eligible to join
the company's pension scheme. The terms of office of the non-executive
directors, which are subject to renewal by agreement, expire not later than at
the conclusion of the annual general meeting in the following calendar years:
J V H Robins 2001
D G Hawkins. 2001
R B Salmon.. 2002
R H Sellier. 2000
However, save in respect of J V H Robins, where twelve months' written
notice is required to be given, appointments may be terminated earlier (without
compensation) by the company giving six months' notice in writing or in certain
other circumstances pursuant to the Articles of Association (including
retirement by rotation) or legislation.
(D) EXECUTIVE DIRECTORS
Executive remuneration packages are designed to attract, motivate and retain
executive directors, and to reward them for enhancing value to shareholders.
The performance measurement of the executive directors and the determination of
their annual remuneration package is undertaken by the committee. No director
attends during any decision about his own remuneration. The committee discusses
with the Group Chief Executive and the Group Chairman the remuneration of the
other executive directors.
There are currently four main elements in the remuneration package for
executive directors:
(a) basic annual salary;
(b) annual bonus payments;
(c) long term incentive arrangements; and
(d) pension arrangements.
Executive directors may accept non-executive appointments outside the
company, subject to the permission of the Board. Fees earned are retained by
each director.
(i) BASIC ANNUAL SALARY
Each executive director's basic salary is determined by the Remuneration
committee at the beginning of each year and when an individual changes position
or responsibility. Following a review on 1 April 2000 basic salaries remain
unchanged from those agreed, and reported previously, and are set out below.
G A Hawker. L267,800
M P Brooker L150,380
J M James.. L195,700
P J Twamley L195,700
(ii) ANNUAL BONUS PAYMENTS
The committee establishes the objectives that must be met for each financial
year if a bonus is to be paid. The committee believes that any incentive
compensation awarded should be tied to the interests of the company's
shareholders. In respect of the year ended 31 March 2000 the principal measures
for annual bonus payments
F-78
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
were, firstly, the profitability of the group, secondly a specific set of
personal objectives for each director and, where applicable, the performance of
that part of the business for which the executive director was responsible. The
maximum annual performance related bonus that can currently be paid is 40% of
basic salary of which a maximum of 10% of basic salary can be paid in relation
to achievement of personal objectives, other than in the case of J M James
where 30% of basic salary can be paid in relation to the achievement of
personal objectives.
No incentive payments have been paid in respect of the year ended 31 March
2000. In 1999 incentive payments varied between 32% and 37%.
Subsequent to the financial year end the committee determined that a bonus
of L50,000 be awarded to JM James. This award was previously disclosed in the
circular issued to Hyder shareholders on 28 April 2000. By way of clarification
of the disclosure set out in the circular, this conditional award is payable
only on successful completion of the Hyder strategic review and is therefore
made in respect of the financial year ending 31 March 2001.
(iii) LONG TERM INCENTIVE ARRANGEMENTS
The long term incentive plan for executive directors was approved by the
annual general meeting on 26 July 1996. A second long term incentive plan
specifically for JM James, which is in all essential terms identical to the
plan approved by shareholders, except that a time related proportion of the
shares earned up to the date of JM James' retirement will be vested and
released at that date, was approved by the Board with effect from 1 April 1998.
The long term incentive plans provide for the conditional award in each year
of ordinary shares in the company worth up to 50% of basic salary. The ordinary
shares in respect of each conditional award only become available to executive
directors to the extent that the performance targets, set at the outset by the
Remuneration committee, have been met over the three year period, commencing
with the conditional award. The performance targets relate to the total
shareholder return, over the three year period commencing with the effective
date of the conditional award, relative to the companies comprising the 250 top
companies by market capitalisation derived from the FTSE 100 and the FTSE mid
250 indices.
The rules of the long term incentive plans provide that if the company's
ranking, by total shareholder return, in the FTSE mid 250 index at the end of
the performance period is lower than ranking position 125 (adjusted as
appropriate if any of the original comparator companies have dropped out of the
top 250 companies), the participants are entitled to no shares.
The ordinary shares for use under the long term incentive plans are
purchased in the market by an employee benefit trust with funds allocated by
the company. The trust conditionally allocated 51,052 ordinary shares to the
participating executive directors at 792.9p per share on 7 July 1999. Of the
51,052 ordinary shares allocated in the year, 46,936 ordinary shares were
reallocated from previously lapsed conditional allocations and 4,116 ordinary
shares were purchased in the market. The additional cost of the 51,052 ordinary
shares allocated in the year was L0.03m. The market value on 31 March 2000 of
the 137,850 shares held by the trust was L0.3m and the original cost was
L1.23m. The cost of the shares is written off over the period of the relevant
conditional allocation. Shares available from lapsed allocations are held by
the trust for conditional allocation in future years.
The table below lists conditional allocations of ordinary shares to each
director under the long term incentive plans, shares which have crystallised
for future vesting in each director pursuant to the scheme rules and lapsed
shares during the year.
F-79
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
On 8 March 2000 the FTSE Equity Indices Committee announced that the market
capitalisation of Hyder was below that necessary to maintain its status as part
of the FTSE mid 250 index.
Accordingly interests under the Hyder LTIP which would ordinarily vest in
April 2001 and April 2002 would not, if present circumstances were to continue,
be capable at those future dates of meeting the performance criteria for these
awards to crystallise. The remuneration committee does not regard it
appropriate at this time to consider exercising its powers under the rules of
the long term incentive plans to modify the exercise criteria.
SHARES PRICE PER
CONDITIONAL 31 INCAPABLE SHARE OF
1 APRIL 1 APRIL 1 APRIL ALLOCATION LAPSED MARCH OF ALLOCATION VESTING
1997 1998 1999 IN YEAR IN YEAR 2000 VESTING* (PENCE) DATE
------- ------- ------- ----------- ------- ------- --------- ---------- ----------
G A Hawker.... 15,162 15,162 4,664 -- -- 4,664 -- 742 April 1999
-- 15,400 15,400 -- (15,400) -- -- 779 April 2000
-- -- 13,279 -- -- 13,279 (13,279) 978 April 2001
-- -- -- 16,887 16,887 (16,887) 793 April 2002
------ ------ ------- ------ ------- ------- ------- --- ----------
15,162 30,562 33,343 16,887 (15,400) 34,830 (30,166)
====== ====== ======= ====== ======= ======= ======= === ==========
M P Brooker... -- 8,663 8,663 -- (8,663) -- -- 779 April 2000
-- -- 7,457 -- -- 7,457 (7,457) 978 April 2001
-- -- -- 9,483 -- 9,483 (9,483) 793 April 2002
------ ------ ------- ------ ------- ------- ------- --- ----------
-- 8,663 16,120 9,483 (8,663) 16,940 (16,940)
====== ====== ======= ====== ======= ======= ======= === ==========
J M James..... -- -- 9,704 -- -- 9,704 (9,704) 978 April 2001
-- -- -- 12,341 -- 12,341 (12,341) 793 April 2002
------ ------ ------- ------ ------- ------- ------- --- ----------
-- -- 9,704 12,341 -- 22,045 (22,045)
====== ====== ======= ====== ======= ======= ======= === ==========
J E Roberts**. 11,455 11,455 3,524 -- -- 3,524 -- 742 April 1999
-- 11,294 11,294 -- (11,294) -- -- 779 April 2000
-- -- 10,215 -- (10,215) -- -- 978 April 2001
------ ------ ------- ------ ------- ------- ------- --- ----------
11,455 22,749 25,033 (21,509) 3,524 --
====== ====== ======= ====== ======= ======= ======= === ==========
S J Doughty*** 10,107 -- -- -- -- -- -- 742 April 1999
-- -- -- -- -- -- -- -- --
-- -- -- -- -- -- -- -- --
-- -- -- -- -- -- -- -- --
------ ------ ------- ------ ------- ------- ------- --- ----------
10,107 -- -- -- -- -- --
====== ====== ======= ====== ======= ======= ======= === ==========
P J Twamley... 10,107 10,107 3,109 -- -- 3,109 -- 742 April 1999
-- 11,294 11,294 -- (11,294) -- -- 779 April 2000
-- -- 9,704 -- -- 9,704 (9,704) 978 April 2001
-- -- -- 12,341 -- 12,341 (12,341) 793 April 2002
------ ------ ------- ------ ------- ------- ------- --- ----------
10,107 21,401 24,107 12,341 (11,294) 25,154 (22,045)
====== ====== ======= ====== ======= ======= ======= === ==========
46,831 83,375 108,307 51,052 (56,866) 102,493 (91,196)
====== ====== ======= ====== ======= ======= ======= === ==========
- --------
* these interests at 31 March 2000 were incapable of vesting because at that
time the market capitalisation of Hyder was below that necessary to
maintain its status as part of the FTSE mid 250 index.
** resigned on 25 May 1999 as a result of which the 21,509 ordinary shares,
conditionally allocated but not yet crystallised, lapsed.
*** resigned on 2 October 1997. All ordinary shares, conditionally allocated
but not yet crystallised, lapsed.
F-80
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Subsequent to the introduction of the long term incentive plan executive
directors are no longer eligible to participate in the company's discretionary
executive share option scheme, although the executive directors can participate
in the employee sharesave scheme which is open to all employees. The
Remuneration committee determines the maximum number of options granted under
the employee sharesave scheme which is an Inland Revenue approved scheme.
(iv) PENSIONARRANGEMENTS
Executive directors are members of the company pension scheme which is
detailed in note 41 to the financial statements. Normal retirement age for
executive directors is 60. Each executive director has been notified on an
individual basis of the estimated pension payable on retirement at 60. The
total pension at 60, including benefits in respect of previous employment, will
be restricted in all cases to a maximum of two-thirds of pensionable pay.
Pensions accrue uniformly between the date of joining the scheme and the normal
retirement date.
Normally an actuarial reduction applies if pensions are paid before the
normal retirement age but there is a discretion to pay pensions unreduced. The
pension for each director is based on his service with the company, together
with service transferred into the company's pension scheme from the director's
previous employers. The pension arrangements provide for a pension on
retirement based on salary alone. Post retirement pension increases are payable
in line with increases in the retail prices index, subject to a maximum of 5%
per annum. Retail prices increases in excess of 5% per annum are paid,
providing the actuary to the Hyder Water Pension Scheme certifies that the
scheme's resources are sufficient. Executive directors' dependants are eligible
for dependant's pensions and the payment of a lump sum in the event of a
director's death in service.
In the case of J M James (who has agreed to continue service for a further
18 months beyond attaining the age of 60) his pension will continue to accrue
during his extended period of service on an uniform basis.
Pension contributions are made on behalf of the executive directors at the
rate of 12.0% (1999 12.0%; 1998 12.0%) of pensionable pay.
To the extent that their benefits from the company scheme are restricted by
Inland Revenue limits, J M James, P J Twamley and J E Roberts have been granted
unfunded pension arrangements which have been set up to provide that part of
each director's pension entitlement which exceeds Inland Revenue limits.
The directors' pension benefits were as follows:
INCREASE/ TRANSFER VALUE
(DECREASE) IN EQUIVALENT OF
AGE AT 31 TOTAL ACCRUED ACCRUED INCREASE/(DECREASE) CONTRIBUTIONS COMPANY
MARCH PENSION AT 31 PENSION IN THE IN ACCRUED PENSION PAID BY EACH PENSION
2000 MARCH 2000 YEAR OVER THE YEAR DIRECTOR COST
--------- ------------- -------------- ------------------- ------------- -------
L000 P.A. L000 P.A. L000 L000 L000
G A Hawker... 52 153 (3) (49) 16 (65)
M P Brooker.. 52 80 2 25 9 16
J M James.... 60 48 4 77 12 65
P J Twamley.. 53 54 4 62 12 50
J E Roberts * 54 17 1 19 3 16
- --------
* resigned on 25 May 1999
F-81
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
The total accrued pension shown is the annual pension which would be payable
from age 60 to which each director would have been entitled, based on service
up to 31 March 2000 and based on 31 March 2000 pay levels. The
increase/(decrease) in accrued pension in the year excludes any increase for
inflation during the year ended 31 March 2000.
The transfer value figures have been calculated on the basis of actuarial
advice in accordance with Actuarial Guidance Note GN11.
The company pension cost is the transfer value equivalent of the increase in
accrued pension less contributions paid by each director. The transfer values
shown make no allowance for the cost of death in service or private health
insurance benefits. Paragraph 4.19 of the Report of Committee on Corporate
Governance (Hampel Report published January 1998) states that the transfer
value represents a liability of the company but not a sum paid or due to the
individual. Accordingly it cannot meaningfully be added to annual remuneration.
The figures for J M James, P J Twamley and J E Roberts include their
unapproved pensions.
Retirement benefits are accruing to four directors under defined benefit
schemes. No directors have benefits accruing under defined contribution schemes.
(E) REMUNERATION POLICY, SERVICE CONTRACTS AND COMPENSATION
In performing its duties, the committee has considered the provisions of
Schedule B of the Combined Code annexed to the London Stock Exchange Listing
Rules.
Directors' service contracts are on a one year rolling basis. In certain
circumstances the company may be obliged to pay compensation for the unexpired
portion of the contract, if it is terminated early. No other payments are made
for compensation for loss of office, and mitigation would normally be applied,
although mitigation does not apply in the event of a change in control. The
executive directors' service contracts will be available for inspection at the
annual general meeting.
(F) REMUNERATION
The combined emoluments of the directors for their services as directors of
the company and its subsidiaries are set out below:
2000 1999 1998
----- ----- -----
L000 L000 L000
Fees............................................. 218 215 222
Salary payments (including benefits in kind)..... 929 1,056 1,106
Performance related bonus........................ -- 345 355
----- ----- -----
1,147 1,616 1,683
Compensation for loss of office.................. -- -- 403
----- ----- -----
1,147 1,616 2,086
===== ===== =====
F-82
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
The directors' emoluments, excluding pension contributions, were as follows:
PERFORMANCE
RELATED BENEFITS IN
SALARY/FEES BONUS KIND TOTAL
----------- ----------- ----------- -----------------
2000 1999 2000 1999 2000 1999 2000 1999 1998
----- ----- ---- ---- ---- ---- ----- ----- -----
L000 L000 L000 L000 L000 L000 L000 L000 L000
G A Hawker..... 268 260 -- 95 13 10 281 365 345
M P Brooker.... 150 146 -- 47 14 13 164 206 181
B H Charles(v). -- -- -- -- -- -- -- -- 64
S J Doughty(vi) -- -- -- -- -- -- -- -- 98
J M James...... 196 190 -- 64 19 19 215 273 250
J E Roberts(iv) 52 200 -- 69 4 12 56 281 259
P J Twamley.... 196 190 -- 70 17 16 213 276 263
----- ----- -- --- -- -- ----- ----- -----
862 986 -- 345 67 70 929 1,401 1,460
===== ===== == === == == ===== ===== =====
J V H Robins(i) 125 113 -- -- -- -- 125 113 14
I R Evans...... -- 15 -- -- -- -- -- 15 126
A J Hales(vii). -- -- -- -- -- -- -- -- 8
D G Hawkins.... 28 28 -- -- -- -- 28 28 25
T Knowles(ii).. 9 28 -- -- -- -- 9 28 25
R B Salmon(iii) 28 3 -- -- -- -- 28 3 --
R H Sellier.... 28 28 -- -- -- -- 28 28 25
----- ----- -- --- -- -- ----- ----- -----
218 215 -- -- -- -- 218 215 223
===== ===== == === == == ===== ===== =====
1,080 1,201 -- 345 67 70 1,147 1,616 1,683
===== ===== == === == == ===== ===== =====
- --------
(i) appointed Group Chairman from 15 May 1998
(ii) retired as a non-executive director on 23 July 1999
(iii) appointed as non-executive director on 24 February 1999
(iv) resigned on 25 May 1999
(v) resigned 25 July 1997
(vi) resigned 2 October 1997, and as a result received the compensation for
loss of office referred to above
(vii) resigned 25 July 1997
F-83
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
HIGHEST PAID DIRECTOR
G A G A G A
HAWKER HAWKER HAWKER
2000 1999 1998
------ ------ ------
L000 L000 L000
Aggregate emoluments.................................... 281 365 345
Gains on share options exercised........................ -- -- 9
---- ---- ----
281 365 354
==== ==== ====
Accrued pension at end of the year under defined benefit
pension schemes....................................... 153 153 139
==== ==== ====
(G) DIRECTORS' INTERESTS IN SHARES
The beneficial interests of the directors in the ordinary shares, preference
shares and options to subscribe for ordinary shares of the company at 31 March
2000, 31 March 1999 and 31 March 1998 were as follows:
CUMULATIVE REDEEMABLE OPTIONS OVER ORDINARY
ORDINARY SHARES OF 120P PREFERENCE SHARES OF L1 SHARES OF 120P
-------------------------- ----------------------- ---------------------
31 MARCH 31 MARCH
31 MARCH 31 MARCH 31 MARCH 31 MARCH 1999 AND 31 MARCH 1999 AND
2000 1999 1998 2000 1998 2000 1998
-------- -------- -------- -------- -------- -------- --------
J V H Robins... 1,109 1,016 1,000 -- -- -- --
G A Hawker..... 14,212 14,212* 13,932 13,408 13,408 894 894
M P Brooker.... 13,158 13,158 13,158 14,408 14,408 794 794
J M James...... 13,084 20,584 28,284 450 450 41,070 41,070
P J Twamley.... 5,202 4,538 4,354 2,070 2,070 14,839 15,076
D G Hawkins.... 577 528 502 -- -- -- --
R B Salmon..... 4,500 -- -- -- -- -- --
R H Sellier.... 294 268 255 252 252 -- --
T Knowles(i)... n/a 5,415 5,415 n/a 5,850 n/a --
J E Roberts(ii) n/a 1,034 1,000 n/a -- n/a 2,484
------ ------ ------ ------ ------ ------ ------
52,136 60,753 67,900 30,588 36,438 57,597 60,318
====== ====== ====== ====== ====== ====== ======
- --------
* The interest of GA Hawker has been revised from that previously reported
following notification of an under-reporting of his PEP interest in a
previous financial period
(i)Retired 23 July 1999
(ii)Resigned 25 May 1999
In addition, at 31 March 2000 R H Sellier was beneficially interested in
7.125% Sterling bonds redeemable in 2004 issued by Welsh Water Utilities
Finance PLC with a nominal value of L9,000 (1999 L9,000).
The above table does not include conditional allocations of shares under the
long term incentive plan, details of which are set out in note 6(c)(iii).
(H) SHARE OPTIONS
No director was granted any share options during the period 1 April 1999 to
31 March 2000.
F-84
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Options held by each of the directors over the ordinary shares of the
company are as below. Options are held under the terms of the employee
sharesave scheme, except as marked sec. which were under the terms of the
executive share option scheme.
SHARES
PRICE ON
OPTION DATE OF
1 APRIL 1 APRIL 1 APRIL GRANTED EXERCISED 31 MARCH PRICE EXERCISE DATE
1997 1998 1999 IN YEAR IN YEAR 2000 (PENCE) (PENCE) EXERCISABLE
----------- ------- ------- ------- --------- -------- ------- -------- --------------
G A Hawker. 1,550 894 894 -- -- 894 650 -- September 2000
=========== ====== ====== == === ====== === === ==============
M P Brooker 2,481 164 164 -- -- 164 521 -- October 2001
-- 630 630 -- -- 630 650 -- September 2000
----------- ------ ------ -- --- ------ --- --- --------------
2,481 794 794 -- -- 794
=========== ====== ====== == === ======
J M James.. sec. 44,938 41,070 41,070 -- -- 41,070 563 -- July 1996
=========== ====== ====== == === ====== === === ==============
P J Twamley sec. 18,707 14,839 14,839 -- -- 14,839 563 -- July 1996
237 237 237 -- 237 -- 523 544 October 1999
----------- ------ ------ -- --- ------ --- --- --------------
18,944 15,076 15,076 -- 237 14,839
=========== ====== ====== == === ======
EXPIRY DATE
-------------
G A Hawker. February 2001
=============
M P Brooker March 2002
February 2001
-------------
J M James.. July 2003
=============
P J Twamley July 2003
March 2000
-------------
In 1998 the directors exercised options which resulted in gains on exercise
of options of L246,000.
On 1 October 1999 PJ Twamley exercised 237 options under the sharesave
scheme. This resulted in a gain on exercise of options by directors during the
year of L48 (1999: nil). The gain is the difference between the share option
price and the share price on the date the share options are exercised.
No other director exercised any options during the 2000 year.
SJ Doughty resigned on 2 October 1997. As at 1 April 1997 he held 57,673
share options, all of which were exercised prior to 31 March 1998.
JE Roberts resigned as a director on 25 May 1999 and subsequently 2,484
options held under the sharesave scheme lapsed.
Executive share option prices are fixed at the closing mid market value on
the day preceding the date of grant. Employee sharesave options are fixed at
the closing mid market value on the day preceding the date of grant less 20%
discount.
All executive share options are exercisable between three and ten years from
the date of grant. Options granted under the employee sharesave scheme are
exercisable within six months after the expiry of a three, five or seven year
save as you earn savings contract. All options may be exercisable earlier in
certain circumstances (such as retirement or redundancy).
The middle market price of an ordinary share at the close of business on 31
March 2000 was 221.75p (1999: 786p; 1998: 978p) and the range during the year
to that date was 179p to 789.5p (1999: 748p to 1,040p; 1998: 774p to 1,049p).
F-85
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(I) STAFF COSTS
2000 1999 1998
----- ----- -----
LM LM LM
Wages and salaries... 231.5 215.3 202.8
Social security costs 16.5 15.9 14.8
Pension costs........ 14.7 14.5 14.3
----- ----- -----
262.7 245.7 231.9
===== ===== =====
Of the above, L38.4m (1999 L43.9m; 1998 L47.3m) has been charged to capital.
(J) AVERAGE MONTHLY NUMBER OF EMPLOYEES DURING THE YEAR (INCLUDING EXECUTIVE
DIRECTORS)
2000 NUMBER 1999 NUMBER 1998 NUMBER
----------- ----------- -----------
Continuing operations:
Regulated water and sewerage activities....... 1,737 1,906 2,071
Regulated electricity distribution activities. 994 1,129 1,279
Infrastructure activities..................... 4,161 3,700 3,454
Managed services activities................... 2,008 1,910 1,536
Other activities.............................. 199 214 199
----- ----- -----
9,099 8,859 8,539
Discontinued operations:
Energy supply activities...................... 193 236 126
Infrastructure activities..................... 254 287 279
----- ----- -----
9,546 9,382 8,944
===== ===== =====
7. GROUP INCOME FROM INVESTMENTS
2000 1999 RESTATED 1998 RESTATED
---- ------------- -------------
LM LM LM
Fixed asset investment income--continuing operations:
Infrastructure activities......................... 3.0 6.5 8.9
Other activities.................................. 0.5 3.4 0.4
--- --- ---
3.5 9.9 9.3
=== === ===
F-86
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
8. PROFIT ON DISPOSAL OF INTERESTS IN INVESTMENTS
2000 1999 1998
---- ---- ----
LM LM LM
Infrastructure activities:
Profit on disposal of investments........................ 2.3 18.6 --
Profit on the grant of option in Transurban Link Limited. -- -- 3.9
--- ---- ---
2.3 18.6 3.9
Other activities:
Profit on disposal of investments........................ 3.4 -- 1.6
--- ---- ---
5.7 18.6 5.5
=== ==== ===
On 21 January 2000 the group disposed of 50% of its interest in Transurban
City Link for L7.3m realising a profit on disposal of L1.3m.
On 25 February 2000 the group received L1.6m in respect of a part disposal
by the Asian Infrastructure Fund of its shares in FLAG (Fibre Optic Cable
Company) following its listing on the New York Stock Exchange, realising a
profit of L1.0m.
On 4 August 1999 the group disposed of its interest in EA Technology Limited
for L0.4m realising a profit of L0.3m.
On 9 August 1999 the group disposed of its interest in UK Data Collection
Services Limited for L3.2m realising a profit of L3.1m.
On 5 May 1998 the group disposed of its interest in National
Telecommunications Inc for L45.3m realising a profit on disposal of L15.3m.
On 13 November 1998 the group disposed of the majority of its interest in
Severoceske Vcodovody a Kanalizace a.s. for L16.0m realising a profit on
disposal of L3.3m after writing back goodwill previously written off directly
to reserves of L2.0m.
On 5 November 1997 the group disposed of its interest in National Grid Group
Plc for L2.8m realising a profit on disposal of L1.6m.
9. GROUP INTEREST PAYABLE
2000 1999 1998
----- ----- -----
LM LM LM
On bank loans and overdrafts 1.7 2.0 1.5
On other loans.............. 152.4 127.8 99.8
On finance leases........... 12.2 13.6 12.2
----- ----- -----
166.3 143.4 113.5
===== ===== =====
F-87
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
10. TAXATION
(A) ORDINARY TAXATION
2000 1999 RESTATED 1998 RESTATED
----- ------------- -------------
LM LM LM
Based on the results for the year:
UK corporation tax at 30% (1999 31%; 1998 31%)..... -- 66.4 10.9
Advance corporation tax (written back)/written off. -- (40.3) 5.9
Deferred taxation.................................. 15.0 -- --
Overseas taxation.................................. 1.0 0.4 (0.1)
Share of joint ventures taxation................... 0.3 0.7 0.8
Share of associated undertakings taxation.......... -- 0.4 0.5
----- ----- ----
16.3 27.6 18.0
Prior year adjustments:
Corporation tax.................................... (14.4) (16.8) 2.8
Overseas taxation.................................. -- (0.1) --
Consortium relief.................................. -- (2.1) (7.2)
----- ----- ----
1.9 8.6 13.6
===== ===== ====
The tax charge on the profit for the year has been reduced by L12.2m (1999
increased by L9.0m; 1998 reduced by L32.8m) in respect of timing differences
for which no deferred tax provision is made, and by L9.7m (1999 Lnil; 1998
L1.6m) in respect of exceptional items incurred in the year (note 5).
The cumulative amount of advance corporation tax written off of L51.2m (1999
L35.3m; 1998 L64.5m) is available for relief against future tax liabilities in
very limited circumstances and therefore has not been treated as reducing the
unprovided amount of deferred taxation as disclosed in note 27(a).
There are losses within the group of approximately L1.0m (1999 L5.0m; 1998
L5.0m) available to carry forward against future profits of those companies
which incurred the losses.
(B) EXCEPTIONAL TAXATION--WINDFALL TAX
The exceptional taxation charge relates to the windfall tax levied on
privatised utility companies. The liability was L281.9m in respect of the two
privatised utility businesses (L192.3m for Hyder plc and L89.6m for South Wales
Electricity plc). The first instalment of L140.9m was paid on 1 December 1997
and the balance of the liability was paid on 1 December 1998.
F-88
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
11. DIVIDENDS
(A) DIVIDENDS ON EQUITY SHARES:
2000 1999 1998
---- ---- ----
LM LM LM
Interim paid of 6.7p per ordinary share (1999 16.8p; 1998 16.2p)........ 10.1 24.8 23.4
Final proposed of nil pence per ordinary share (1999 33.6p; 1998 34.2p
including 1.5p per share compensation for delayed payment)............ -- 49.7 49.9
---- ---- ----
Total paid and proposed 6.7p per ordinary share (1999 50.4p; 1998 50.4p) 10.1 74.5 73.3
==== ==== ====
(B) DIVIDENDS ON NON-EQUITY SHARES:
2000 1999 1998
---- ---- ----
LM LM LM
Dividends of 7.875p (net) per preference share (1999 7.875p (net); 1998
7.875p (net))........................................................ 16.4 16.4 16.4
==== ==== ====
12. EARNINGS PER SHARE
2000 1999 1998
-------------------------- -------------------------- ---------------------------
(LOSS)/
PROFIT EARNINGS PER PROFIT EARNINGS PER PROFIT (LOSS)/EARNINGS
ATTRIBUTABLE SHARE ATTRIBUTABLE SHARE ATTRIBUTABLE PER SHARE
TO ORDINARY ------------- TO ORDINARY ------------- TO ORDINARY --------------
SHAREHOLDERS BASIC DILUTED SHAREHOLDERS BASIC DILUTED SHAREHOLDERS BASIC DILUTED
------------ ----- ------- ------------ ----- ------- ------------ ----- -------
LM PENCE PENCE LM PENCE PENCE LM PENCE PENCE
Profit attributable to ordinary shareholders 58.2 39.0 39.0 181.0 123.4 122.5 (143.7) (99.8) (98.4)
Adjusting items:
Exceptional items (net of taxation)...... 118.9 79.6 79.5 -- -- -- 38.4 26.7 26.3
Windfall tax............................. -- -- -- -- -- -- 281.9 195.8 193.0
Profit on disposal of group operations
(net of taxation)....................... (32.0) (21.4) (21.4) -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ------ ----- -----
Adjusted profit attributable to ordinary
shareholders............................... 145.1 97.2 97.1 181.0 123.4 122.5 176.6 122.7 120.9
===== ===== ===== ===== ===== ===== ====== ===== =====
EARNINGS PER SHARE HAVE BEEN CALCULATED BASED UPON:
2000 1999 1998
-------------- -------------- --------------
BASIC DILUTED BASIC DILUTED BASIC DILUTED
NUMBER NUMBER NUMBER NUMBER NUMBER NUMBER
------ ------- ------ ------- ------ -------
(IN MILLIONS)
Weighted average ordinary shares in
issue............................ 149.3 149.4 146.7 147.7 143.9 146.0
===== ===== ===== ===== ===== =====
F-89
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
The weighted average number of shares disclosed above is stated after
excluding the 3.5m (1999 3.7m; 1998 3.9m) weighted average ordinary shares
held by the qualifying employee share options trust and under the executive
directors' long term incentive plan, the shares in which are treated as held by
the company until they vest. The difference between the basic and diluted
weighted average number of ordinary shares in issue is wholly attributable to
outstanding share options.
13. INTANGIBLE FIXED ASSETS
GROUP
FISHING GOODWILL GOODWILL
RIGHTS (POSITIVE) (NEGATIVE) TOTAL
------- ---------- ---------- -----
LM LM LM LM
COST
At 1 April 1999..... 0.9 5.2 (1.8) 4.3
Additions........... -- 0.3 0.1 0.4
Disposals........... (0.9) -- -- (0.9)
---- --- ---- ----
At 31 March 2000.... -- 5.5 (1.7) 3.8
==== === ==== ====
AMOUNTS PROVIDED
At 1 April 1999..... 0.5 -- -- 0.5
Provided in the year -- 0.3 -- 0.3
Disposals........... (0.5) -- -- (0.5)
---- --- ---- ----
At 31 March 2000.... -- 0.3 -- 0.3
==== === ==== ====
NET BOOK VALUE
At 31 March 2000.... -- 5.2 (1.7) 3.5
==== === ==== ====
At 31 March 1999.... 0.4 5.2 (1.8) 3.8
==== === ==== ====
Goodwill is amortised over a period of 20 years being the directors'
estimate of the useful economic life of these assets. Negative goodwill has
resulted from acquisitions where net assets are acquired at a discount to the
book value of net assets and is amortised between 2.5 years and 20 years.
F-90
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
14. TANGIBLE FIXED ASSETS
GROUP
VEHICLES,
PLANT,
EQUIPMENT,
WATER & COMPUTER
SEWAGE ELECTRICITY HARDWARE
FREEHOLD LEASEHOLD INFRA- DISTRIBUTION AND
LAND & PROPERTIES & STRUCTURE OPERATIONAL NETWORK CAPITALISED
BUILDINGS IMPROVEMENTS ASSETS STRUCTURES ASSETS SOFTWARE TOTAL
--------- ------------ --------- ----------- ------------ ----------- -------
LM LM LM LM LM LM LM
COST OR VALUATION
At 1 April 1999........... 76.9 6.7 1,060.0 1,425.5 902.4 435.8 3,907.3
Exchange difference....... (0.5) (0.1) -- -- -- (0.1) (0.7)
Additions................. 1.8 0.2 137.8 119.6 62.5 41.5 363.4
Grants and contributions.. -- -- (6.6) (1.4) -- -- (8.0)
Amounts written off....... (3.1) -- -- -- -- (80.2) (83.3)
Disposals................. (0.4) (3.9) (1.0) -- (1.8) (18.6) (25.7)
Sale of group operations.. -- -- -- -- -- (20.9) (20.9)
---- ---- ------- ------- ----- ----- -------
At 31 March 2000.......... 74.7 2.9 1,190.2 1,543.7 963.1 357.5 4,132.1
==== ==== ======= ======= ===== ===== =======
ACCUMULATED DEPRECIATION
At 1 April 1999........... 21.3 2.2 240.4 315.0 275.7 220.3 1,074.9
Exchange difference....... (0.1) -- -- -- -- -- (0.1)
Charge for the year....... 1.7 0.3 34.7 39.1 25.1 39.5 140.4
Amounts written off....... (1.0) -- -- -- -- (5.7) (6.7)
Disposals................. (0.1) (1.0) (1.0) -- (1.4) (17.0) (20.5)
Sale of group operations.. -- -- -- -- -- (7.0) (7.0)
---- ---- ------- ------- ----- ----- -------
At 31 March 2000.......... 21.8 1.5 274.1 354.1 299.4 230.1 1,181.0
==== ==== ======= ======= ===== ===== =======
NET BOOK VALUE
At 31 March 2000.......... 52.9 1.4 916.1 1,189.6 663.7 127.4 2,951.1
==== ==== ======= ======= ===== ===== =======
At 31 March 1999.......... 55.6 4.5 819.6 1,110.5 626.7 215.5 2,832.4
==== ==== ======= ======= ===== ===== =======
ANALYSIS OF NET BOOK VALUE
At 31 March 2000
Owned..................... 52.9 0.8 916.1 964.1 663.7 127.0 2,724.6
Held under finance leases. -- 0.6 -- 225.5 -- 0.4 226.5
---- ---- ------- ------- ----- ----- -------
52.9 1.4 916.1 1,189.6 663.7 127.4 2,951.1
==== ==== ======= ======= ===== ===== =======
- --------
(a) Tangible fixed assets at 31 March 2000 include L428.1m (1999 L429.5m) of
assets in the course of construction, which are not depreciated until
commissioned.
(b) The net book value of leasehold properties and improvements comprise:
2000 1999
---- ----
LM LM
Long leasehold..... 1.4 0.6
Short leasehold.... -- 3.9
--- ---
Total leasehold. 1.4 4.5
=== ===
(c) Electricity distribution network assets include assets leased to third
parties under operating leases. The cost of these was L3.8m (1999 L3.8m)
and accumulated depreciation amounted to L1.1m (1999 L0.9m) at 31 March
2000.
F-91
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(d) The accounting treatment for grants and customer contributions in respect
of infrastructure assets is set out in the principal accounting policies.
This treatment is not in accordance with schedule 4 to the Companies Act
1985. As a consequence the net book value of fixed assets and deferred
income is L156.3m (1999 L140.2m) lower than it would have been had this
treatment not been adopted.
COMPANY
VEHICLES, PLANT,
EQUIPMENT AND
FREEHOLD LAND AND COMPUTER HARDWARE &
BUILDINGS CAPITALISED SOFTWARE TOTAL
----------------- -------------------- -----
LM LM LM
COST
At 1 April 1999......... 0.8 2.4 3.2
Additions............... -- 0.1 0.1
--- --- ---
At 31 March 2000........ 0.8 2.5 3.3
=== === ===
ACCUMULATED DEPRECIATION
At 1 April 1999......... -- 0.8 0.8
Charge for the year..... -- 0.3 0.3
--- --- ---
At 31 March 2000........ -- 1.1 1.1
=== === ===
NET BOOK VALUE
At 31 March 2000........ 0.8 1.4 2.2
=== === ===
At 31 March 1999........ 0.8 1.6 2.4
=== === ===
15. INVESTMENT PROPERTIES
GROUP
LM
----
At 1 April 1999................ 9.4
Adjustment to open market value 1.5
----
At 31 March 2000............... 10.9
====
Investment properties were valued at 31 March 2000 by Cooke & Arkwright, a
firm of Chartered Surveyors, on the basis of open market value. These
properties are rented to third parties under operating leases. Investment
properties comprise L10.9m (1999 L9.4m) of freehold properties.
The accounting treatment for investment properties is set out in the
principal accounting policies. This treatment is not in accordance with
schedule 4 to the Companies Act 1985. As a consequence the profit before
interest for the year is L0.2m (1999 L0.2m) higher than it would have been had
this treatment been adopted.
F-92
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
16. FIXED ASSET INVESTMENTS
GROUP
INTERESTS INTERESTS IN
OWN IN JOINT ASSOCIATED LISTED UNLISTED
SHARES VENTURES UNDERTAKINGS INVESTMENTS INVESTMENTS TOTAL
------ --------- ------------ ----------- ----------- -----
LM LM LM LM LM LM
COST
At 1 April 1999.......... 21.7 20.4 9.9 46.5 19.4 117.9
Exchange differences..... -- (0.1) 0.1 -- (0.1) (0.1)
Additions................ -- 16.5 -- 1.8 -- 18.3
Disposals................ (1.4) -- -- (6.6) (0.2) (8.2)
Share of retained profits -- 0.9 0.6 -- -- 1.5
Reclassification......... -- 0.1 (0.1) (4.3) -- (4.3)
---- ---- ---- ---- ---- -----
At 31 March 2000......... 20.3 37.8 10.5 37.4 19.1 125.1
==== ==== ==== ==== ==== =====
AMOUNTS PROVIDED
At 1 April 1999.......... -- -- 0.1 3.0 0.8 3.9
Disposals................ -- -- -- (1.1) -- (1.1)
Provided in the year..... 10.0 -- -- 1.6 -- 11.6
---- ---- ---- ---- ---- -----
At 31 March 2000......... 10.0 -- 0.1 3.5 0.8 14.4
==== ==== ==== ==== ==== =====
NET BOOK VALUE
At 31 March 2000......... 10.3 37.8 10.4 33.9 18.3 110.7
==== ==== ==== ==== ==== =====
At 31 March 1999......... 21.7 20.4 9.8 43.5 18.6 114.0
==== ==== ==== ==== ==== =====
The market value of the listed investments, excluding the group's L27.9m
(1999 L27.1m) investment in the Asian Infrastructure Fund, is L15.4m (1999
L31.1m).
The directors consider that the market value of the group's investment in
the Asian Infrastructure Fund, which is a closed end fund with no ready market
for the shares, is not materially different from the carrying value of that
investment.
The listed investment of L4.3m has been reclassified as a current asset
investment (note 19).
Own shares relate to ordinary shares purchased under the qualifying employee
share option trust (note 30(c)) and the executive directors' long term
incentive plan (note 30(b)). The nominal value of these shares is L4.1m (1999
L4.3m).
F-93
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
COMPANY
INTERESTS IN
OWN GROUP UNLISTED
SHARES UNDERTAKINGS INVESTMENTS TOTAL
------ ------------ ----------- -------
LM LM LM LM
COST
At 1 April 1999..... 21.7 1,549.9 0.4 1,572.0
Additions........... -- 64.0 -- 64.0
Disposals........... (1.4) -- -- (1.4)
---- ------- --- -------
At 31 March 2000.... 20.3 1,613.9 0.4 1,634.6
==== ======= === =======
AMOUNTS PROVIDED
At 1 April 1999..... -- 1.4 0.3 1.7
Provided in the year 10.0 76.1 -- 86.1
---- ------- --- -------
At 31 March 2000.... 10.0 77.5 0.3 87.8
==== ======= === =======
NET BOOK VALUE
At 31 March 2000.... 10.3 1,536.4 0.1 1,546.8
==== ======= === =======
At 31 March 1999.... 21.7 1,548.5 0.1 1,570.3
==== ======= === =======
Principal group undertakings are listed in note 44.
17. STOCKS AND WORK IN PROGRESS
GROUP
2000 1999
---- ----
LM LM
Raw materials and consumables...... 7.8 8.8
Work in progress................... 9.0 6.5
Finished goods and goods for resale 0.1 0.7
---- ----
16.9 16.0
==== ====
The replacement cost of stocks is not materially different from their
carrying value.
F-94
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
18. DEBTORS
GROUP COMPANY
----------- -----------
2000 1999 2000 1999
----- ----- ----- -----
LM LM LM LM
AMOUNTS FALLING DUE WITHIN ONE YEAR:
Trade debtors.................................... 101.6 145.2 -- --
Amounts recoverable on contracts................. 29.2 26.1 -- --
Amounts owed by subsidiary undertakings.......... -- -- 353.8 410.9
Amounts owed by associated undertakings.......... 0.7 0.5 -- --
Net investment in finance leases................. 0.2 0.1 -- --
Other debtors.................................... 29.6 40.1 0.6 3.2
Prepayments and accrued income................... 62.1 91.8 10.1 9.3
Amounts due on sale of group operations (note 39) 11.2 -- -- --
----- ----- ----- -----
234.6 303.8 364.5 423.4
AMOUNTS FALLING DUE AFTER MORE THAN ONE YEAR:
Net investment in finance leases................. 1.6 1.0 -- --
Other debtors.................................... 1.8 9.4 -- --
----- ----- ----- -----
238.0 314.2 364.5 423.4
===== ===== ===== =====
19. CURRENT ASSET INVESTMENTS
MANAGEMENT OF LIQUID RESOURCES
GROUP COMPANY
----------- -----------
2000 1999 2000 1999
----- ----- ----- -----
LM LM LM LM
INVESTMENTS IN:
Sterling fixed term and call deposits. 397.2 470.5 339.8 381.9
Sterling denominated commercial papers 31.8 120.8 14.9 82.5
----- ----- ----- -----
429.0 591.3 354.7 464.4
Listed investment held for resale..... 4.3 -- -- --
----- ----- ----- -----
433.3 591.3 354.7 464.4
===== ===== ===== =====
AMOUNTS BECOMING DUE:
Within one year....................... 433.3 591.3 354.7 464.4
===== ===== ===== =====
The fixed asset investment held for resale is the group's 20% interest in
the issued share capital of Severoceske Vodovody a Kanalizace a.s. ("ScVK")
which is held at cost. The market value of the ScVK investment is L2.6m (1999
L1.9m). The company has not reduced the carrying value of this investment as
the company has a put option which requires a third party to purchase this
investment at a price greater than the carrying value. The directors do not
consider that the group's 20% interest in ScVK gives them significant influence
over the operations of that company to include the investment as an associate.
F-95
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
20. CREDITORS
(A)AMOUNTS FALLING DUE WITHIN ONE YEAR
GROUP COMPANY
----------- -----------
NOTE 2000 1999 2000 1999
---- ----- ----- ----- -----
LM LM LM LM
Bank loans and overdrafts.................... 5.8 0.6 -- --
Loan notes................................... 21(d) 4.2 6.3 3.4 6.3
Other loans.................................. 21(c) 8.1 54.7 -- 6.4
Obligations under finance leases............. 22 0.3 0.3 -- --
Payments received on account on contracts.... 19.9 18.1 -- --
Trade creditors.............................. 115.6 145.1 -- --
Amounts owed to subsidiary undertakings...... -- -- 0.2 1.0
Loans from subsidiary undertakings........... -- -- 50.0 --
Dividends payable............................ 2.7 112.5 2.7 112.5
Corporation tax.............................. 12.8 28.0 -- 3.0
Other taxation and social security........... 13.0 12.3 -- 0.1
Other creditors.............................. 89.1 88.0 -- --
Accruals and deferred income................. 86.4 90.4 57.0 48.1
Capital commitments due to joint ventures and
associates................................. 5.7 -- -- --
----- ----- ----- -----
363.6 556.3 113.3 177.4
===== ===== ===== =====
(B) AMOUNTS FALLING DUE AFTER MORE THAN ONE YEAR
GROUP COMPANY
----------------- ---------------
NOTE 2000 1999 2000 1999
---- --------- ------- ------- -------
LM LM LM LM
Sterling bonds................................... 21(a) 1,024.9 1,024.5 678.7 678.4
US$ bonds........................................ 21(b) 615.4 615.2 615.4 615.2
Other loans...................................... 21(c) 212.9 219.1 10.8 8.6
Obligations under finance leases................. 22 265.5 265.7 -- --
Creditors between one and five years: -- --
Capital commitments due to joint ventures and
associates.................................. 17.7 10.3 -- --
Refundable customer contributions............. 4.0 4.9 -- --
Other......................................... 3.1 7.3 -- --
------- ------- ------- -------
2,143.5 2,147.0 1,304.9 1,302.2
======= ======= ======= =======
F-96
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
21. LOANS
(A) STERLING BONDS
INTEREST NOMINAL PREMIUM ISSUE NET NET COSTS CARRYING
MATURITY DATE RATE VALUE ON ISSUE COSTS PROCEEDS AMORTISED VALUE
------------- -------- ------- -------- ----- -------- --------- --------
% LM LM LM LM LM LM
GROUP
2002...... 10.750 75.0 -- (1.0) 74.0 0.8 74.8
2004...... 7.125 100.0 1.1 (2.0) 99.1 0.5 99.6
2006...... 8.750 200.0 3.2 (2.3) 200.9 (0.1) 200.8
2014...... 7.625 100.0 0.8 (2.6) 98.2 0.5 98.7
2016...... 9.500 200.0 6.8 (1.9) 204.9 (0.3) 204.6
2020...... 9.250 150.0 1.7 (3.9) 147.8 0.1 147.9
2020...... 7.000 200.0 -- (1.6) 198.4 0.1 198.5
------- ---- ----- ------- ---- -------
1,025.0 13.6 (15.3) 1,023.3 1.6 1,024.9
======= ==== ===== ======= ==== =======
COMPANY
2002...... 10.750 75.0 -- (1.0) 74.0 0.8 74.8
2006...... 8.750 200.0 3.2 (2.3) 200.9 (0.1) 200.8
2016...... 9.500 200.0 6.8 (1.9) 204.9 (0.3) 204.6
2020...... 7.000 200.0 -- (1.6) 198.4 0.1 198.5
------- ---- ----- ------- ---- -------
675.0 10.0 (6.8) 678.2 0.5 678.7
======= ==== ===== ======= ==== =======
(B) US$BONDS
INTEREST NOMINAL PREMIUM ISSUE NET NET COSTS CARRYING
MATURITY DATE RATE VALUE ON ISSUE COSTS PROCEEDS AMORTISED VALUE
------------- -------- ------- -------- ----- -------- --------- --------
% LM LM LM LM LM LM
GROUP & COMPANY
2004........... 6.750 120.0 0.8 (1.4) 119.4 0.2 119.6
2007........... 6.875 120.0 0.8 (1.4) 119.4 0.1 119.5
2008........... 6.500 136.0 1.9 (2.1) 135.8 -- 135.8
2017........... 7.250 60.0 0.4 (0.7) 59.7 -- 59.7
2028........... 7.375 181.0 2.6 (2.9) 180.7 0.1 180.8
----- --- ---- ----- --- -----
617.0 6.5 (8.5) 615.0 0.4 615.4
===== === ==== ===== === =====
Fixed interest rates on the sterling/US$ cross currency interest rate swaps
used to cover the US$ bonds referred to above range between 6.8% and 8.1%. The
full nominal value of US$1,025m was simultaneously swapped for sterling to
match the future US$ repayment liabilities at maturity.
F-97
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(C) OTHER LOANS
GROUP COMPANY
----------- ---------
2000 1999 2000 1999
----- ----- ---- ----
LM LM LM LM
REPAYABLE AS FOLLOWS:
Within one year......................................... 8.1 54.7 -- 6.4
Between one and two years............................... 18.3 7.4 10.8 --
Between two and five years.............................. 24.2 24.5 -- --
After more than five years.............................. 170.4 187.2 -- 8.6
----- ----- ---- ----
221.0 273.8 10.8 15.0
===== ===== ==== ====
Repayable wholly within five years...................... 11.2 49.0 10.8 6.4
Repayable wholly after five years....................... 140.0 148.6 -- 8.6
Repayable by instalments after five years............... 69.8 76.2 -- --
----- ----- ---- ----
221.0 273.8 10.8 15.0
===== ===== ==== ====
THESE LOANS ARE DENOMINATED IN THE FOLLOWING CURRENCIES:
Sterling................................................ 206.4 243.7 -- --
Australian $............................................ -- 11.7 -- --
US$..................................................... 10.0 8.6 10.0 8.6
Canadian $.............................................. -- 6.4 -- 6.4
German marks............................................ 3.8 3.4 -- --
Euros................................................... 0.8 -- 0.8 --
----- ----- ---- ----
221.0 273.8 10.8 15.0
===== ===== ==== ====
Fixed interest rates on these loans range between 6.5% and 10.2% (1999 5.2%
and 10.2%) and variable interest rates varied between 1.0% below to 0.2% above
LIBOR (1999 1.0% below to 0.2% above LIBOR) (London Interbank offer rate).
(D) LOANNOTES
The loan notes were issued in lieu of all or part of the cash consideration
due under the offer for South Wales Electricity plc to those of its
shareholders who elected as such. The notes bear interest, payable half yearly
in arrears, at the rate of 1% below six month LIBOR.
22. FINANCE LEASES
GROUP
2000 1999
----- -----
LM LM
AMOUNTS DUE UNDER FINANCE LEASES ARE PAYABLE AS FOLLOWS:
Within one year......................................... 0.3 0.3
Between one and two years............................... 0.1 0.2
Between two and five years.............................. -- 0.1
After more than five years.............................. 265.4 265.4
----- -----
265.8 266.0
===== =====
F-98
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
A long dated interest rate swap was arranged on 1 April 1994 which has the
effect of fixing the rate of interest at 7.8% on floating rate sterling finance
lease obligations of L57.9m (1999 L59.3m). The obligations under the swap and
the finance lease reduce over a remaining period of 14 years.
23. MATURITY OF FINANCIAL LIABILITIES
The maturity profile of the group's gross borrowings, preference shares and
other financial liabilities, excluding bank overdrafts, was as follows:
2000 1999
------- -------
LM LM
GROSS BORROWINGS:
In one year or less, or on demand.................. 12.6 61.3
In more than one year but not more than two years.. 94.8 7.6
In more than two years but not more than five years 249.8 198.7
In more than five years............................ 1,774.1 1,918.2
------- -------
2,131.3 2,185.8
======= =======
PREFERENCE SHARES:
In more than five years............................ 206.6 206.6
OTHER FINANCIAL LIABILITIES:
In more than one year but not more than two years.. 3.0 7.7
In more than two years but not more than five years 17.5 5.8
In more than five years............................ 4.3 9.0
------- -------
2,362.7 2,414.9
======= =======
24. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
(A) TREASURY MANAGEMENT AND FINANCIAL INSTRUMENTS
Group treasury activities are managed centrally within a formal set of
treasury policies and objectives which are regularly reviewed and approved by
the Board. The group's policy specifically prohibits any transactions of a
speculative nature and does not envisage the use of complex financial
instruments. The treasury team uses financial instruments including
derivatives, to raise finance and to manage risk from its operations. Surplus
cash is invested in short to medium term sterling financial investments. The
Board annually establishes the investment criteria which is restricted to banks
or other institutions meeting required standards assessed by reference to the
major credit rating agencies.
The main treasury management risks faced relate to interest rate risk,
liquidity risk and foreign currency risk. The Board reviews and agrees policies
for managing these risks as summarised below.
(B) FINANCE AND INTEREST RATE RISK
The group's policy is to finance operating subsidiaries by a mixture of
retained profits, bank borrowings, finance leases and long term loans.
The group's policy is to keep the greater proportion of gross borrowings at
fixed rates of interest. Derivatives, predominately interest rate swaps and
forward rate agreements, are used to help manage the mix of
F-99
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
fixed and floating rate debt. At the year end, after taking account of interest
rate swaps 89% (1999 87%) of gross borrowings of L2,131m, were at long term
fixed interest rates, fixed for an average period of 12.9 years (1999 13.8
years). The remaining 11% (1999 13%) were at floating rates of interest.
Exposure to floating rate debt of L244m (1999 L291m) is hedged against
interest rate movements by cash balances and deposits of L457m (1999 L612m).
Decisions on fixing interest rates on the floating rate loans will continue to
be considered as cash and deposit balances are utilised. The net effect of an
average increase in interest rates of 1% on the variable rate components of the
group's short term floating rate loans and cash balances during the year would
have resulted in an increase in profit before tax of L2.1m (1999 L0.5m).
(C) LIQUIDITY RISK
The group's objective is to maintain a balance between continuity of funding
and flexibility through the use of borrowings with a range of maturity dates.
The group's policy is to ensure that the maturity profile does not place an
excessive strain on the group's ability to repay loans. Currently no more than
17% (1999 16%) of our borrowings mature in any twelve month period. In
addition, to preserve continuity of funding, at least 83% of borrowings will
mature in more than five years and at least 53% in more than ten years.
At the year end, 1% (1999 2%) of gross borrowings were due to mature in the
next twelve months; 16% (1999 10%) will mature in the following four years and
83% (1999 88%) thereafter.
In addition, the group's practice is to maintain adequate undrawn committed
facilities of at least 10% of borrowings in order to provide flexibility in the
management of the group's liquidity. At the year end we had multicurrency
committed facilities of L450m with ten banks of which L10.8m (1999 L14.7m) had
been utilised. The L10.8m utilisation relates to foreign currency loans
required for overseas investments thus creating a natural hedge. The weighted
average period until maturity of these facilities was 2.4 years.
Short term flexibility is achieved by managing an investment portfolio of
short term money market deposits and commercial paper purchases.
(D) FOREIGN CURRENCY RISK
Cumulative US Bond issues amounting to US$1,025m have been converted into
sterling as L617m.
The group has entered into US dollar swaps which ensure that the group is
not exposed to any currency exposure when the dollar repayments fall due.
The group has also entered into cross currency interest rate swaps whereby
the dollar coupon rates were exchanged for sterling interest rates.
The group has a number of overseas subsidiaries, joint venture and associate
entities reporting in local currencies and in order to protect the group's
sterling balance sheet from the movements in the respective currency/sterling
exchange rate, the group finances certain net investments in subsidiary, joint
ventures and associate entities by means of related currency borrowings.
The group also has transactional currency exposures which arise from sales
and purchases by operating units in currencies other than the group's reporting
currency. All operating units are required to notify the treasury team of all
material currency contracts and commitments which potentially create currency
exposure on either a transaction or translation basis in order that the
currency exposure can be minimised.
F-100
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
At the year end, after taking into account the effects of forward foreign
exchange contracts, the group had foreign currency exposures with a net
unrealised loss of L1m (1999 L1m) in respect of unhedged foreign currency fixed
asset investments.
On average, foreign currencies relating to group activities did not move
materially against sterling during the year. Shareholders' funds were however
reduced by L1.3m at 31 March 2000 (1999 L0.2m increase) due to foreign exchange
movements affecting overseas debt, cash balances and other assets.
(E) CONTRACTS FOR DIFFERENCES
Contracts for differences (CFDs) existed within the energy supply business
prior to the disposal of the business to British Energy on 17 February 2000.
The CFDs largely insulated the group against the effects of variability of
electricity pool prices.
Any obligations arising under the CFDs were taken over by British Energy
when they acquired the energy supply businesses. No residual risk resides
within Hyder and as a consequence the unutilised power purchase provision of
L59.3m (note 27(e)) on 17 February 2000 was released to the profit and loss
account as part of the profit on disposal of group operations (note 39).
(F) SHORT TERM DEBTORS AND CREDITORS
Short term debtors and creditors have been excluded from the following
disclosures, other than the currency risk disclosures.
(G) INTEREST RATE SWAPS
The group and company have entered into interest rate swap arrangements in
order to manage the interest rate exposure of the group and the company and not
for trading or speculative purposes.
GROUP
The group's outstanding interest rate swap arrangements had a notional
principal balance of L724.9m (1999 L755.5m), with termination dates ranging
between December 2004 and December 2028 (1999 December 1999 and December 2028),
and interest rates ranging between 6.8% and 8.3% (1999 6.0% and 8.4%).
COMPANY
At 31 March 2000 the company's outstanding interest rate swap arrangements
had a notional principal balance of L617.0m (1999 L617.0m) with termination
dates ranging between December 2004 and December 2028 (1999 December 2004 and
December 2028), and interest rates ranging between 6.8% and 8.1% (1999 6.9% and
8.2%).
F-101
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(H) CURRENCY AND INTEREST RATE PROFILE OF FINANCIAL LIABILITIES
After taking into account the various interest rate and forward foreign
currency swaps entered into by the group, the fixed and floating interest rate
profile of the group's financial liabilities by currency was as follows:
TOTAL FIXED RATE FLOATING RATE
--------------- --------------- -------------
CURRENCY 2000 1999 2000 1999 2000 1999
-------- ------- ------- ------- ------- ----- -----
LM LM LM LM LM LM
GROSS BORROWINGS:
Sterling.................... 2,116.7 2,155.7 1,887.7 1,894.9 229.0 260.8
US$......................... 10.0 8.6 -- -- 10.0 8.6
Australian $................ -- 11.7 -- -- -- 11.7
Canadian $.................. -- 6.4 -- -- -- 6.4
German marks................ 3.8 3.4 -- -- 3.8 3.4
Euros....................... 0.8 -- -- -- 0.8 --
------- ------- ------- ------- ----- -----
2,131.3 2,185.8 1,887.7 1,894.9 243.6 290.9
PREFERENCE SHARES:
Sterling.................... 206.6 206.6 206.6 206.6 -- --
OTHER FINANCIAL LIABILITIES:
Sterling.................... 19.8 15.4 -- -- -- --
Australian $................ 4.6 5.1 -- -- -- --
German marks................ 0.4 -- -- -- -- --
Finnish marks............... -- 2.0 -- -- -- --
------- ------- ------- ------- ----- -----
2,362.7 2,414.9 2,094.3 2,101.5 243.6 290.9
======= ======= ======= ======= ===== =====
The floating rate borrowings comprise:
--loans from the European Investment Bank that bear interest based on
sterling LIBOR rates;
--sterling denominated bank borrowings that bear interest based on
sterling LIBOR rates;
--finance leases;
--loan notes that bear interest based on sterling LIBOR rates; and,
--foreign currency denominated bank borrowings that bear interest based
on prevailing interbank borrowing rates.
No interest is paid on the other financial liabilities.
All overseas currency borrowings set out in the above table are fully hedged
against assets denominated in those currencies.
(I) INTEREST RATE PROFILE OF FINANCIAL LIABILITIES
FIXED RATE FINANCIAL LIABILITIES
WEIGHTED AVERAGE PERIOD FOR
WEIGHTED AVERAGE INTEREST RATE WHICH RATE IS FIXED
------------------------------ --------------------------------
CURRENCY 2000 1999 2000 1999
- -------- ---- ---- ----- -----
% % YEARS YEARS
Sterling:
Borrowings........ 8.0 8.0 12.9 13.8
Preference shares. 7.9 7.9 13.3 14.3
=== === ==== ====
F-102
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
No interest is paid on the other financial liabilities. The figures in the
above table take into account the interest rate and forward foreign currency
swaps used to manage the group's fixed interest rate profile.
(J) BORROWINGFACILITIES
Undrawn committed borrowing facilities were:
2000 1999
----- -----
LM LM
Committed borrowing facilities available 450.0 450.0
Drawn down as at 31 March............... (10.8) (14.7)
----- -----
Expiring after more than two years...... 439.2 435.3
===== =====
(K) CURRENCY AND INTEREST RATE PROFILE OF FINANCIAL ASSETS
2000 1999
-------------------------- --------------------------
SHORT SHORT
CASH NET TERM CASH NET TERM
OF DEPOSITS OF DEPOSITS
OVERDRAFTS (NOTE 19) TOTAL OVERDRAFTS (NOTE 19) TOTAL
---------- --------- ----- ---------- --------- -----
LM LM LM LM LM LM
CURRENCY:
Sterling........................... 8.6 428.7 437.3 10.7 568.1 578.8
US Dollars......................... 4.1 0.1 4.2 1.6 -- 1.6
EU currencies (other than Sterling) 13.6 0.2 13.8 2.2 5.3 7.5
Other currencies................... 1.9 -- 1.9 5.9 17.9 23.8
---- ----- ----- ---- ----- -----
28.2 429.0 457.2 20.4 591.3 611.7
==== ===== ===== ==== ===== =====
LONG TERM DEBTORS:
Sterling........................... -- -- 3.4 -- -- 10.4
---- ----- ----- ---- ----- -----
At 31 March........................ 28.2 429.0 460.6 20.4 591.3 622.1
==== ===== ===== ==== ===== =====
CURRENCY:
Floating rate...................... 28.2 0.6 28.8 20.4 -- 20.4
Fixed rate......................... -- 428.4 428.4 -- 591.3 591.3
LONG TERM DEBTORS:
Nil interest rate.................. -- -- 3.4 -- -- 10.4
---- ----- ----- ---- ----- -----
At 31 March........................ 28.2 429.0 460.6 20.4 591.3 622.1
==== ===== ===== ==== ===== =====
The sterling money market deposits above comprise deposits placed on money
markets from overnight to four months. All the investments in commercial paper
are at fixed interest rates. The weighted average interest rate on commercial
paper and money market deposits is 5.7% (1999 5.5%) and the weighted average
time for which they are held is 55 days (1999 71 days). These assets are held
as part of the financing arrangements of the group.
Cash generated from operating activities and from long term loan drawdowns
in advance of future capital expenditure obligations is invested on a daily
basis in money market investments. These investments include term deposits,
government securities and corporate bonds and papers rated at not less than AA.
F-103
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(L) FAIR VALUES OF FINANCIAL INSTRUMENTS
In the table below the fair value of short term borrowings, current asset
investments, cash at bank and in hand and bank loans and overdrafts
approximates to book values due to the short maturity of these instruments. The
fair value of long term borrowings has been determined by reference to prices
available from the financial markets on which these borrowings are traded. The
fair value fundamentally represents the change in anticipated future interest
rates and foreign exchange rates, to the dates of maturity of the borrowings,
between the date those long term borrowings were raised and the year end. The
preference shares are listed on the London Stock Exchange and the fair value
has been quoted at the listed price. The fair value of interest rate swaps and
combined interest rate and forward foreign currency swaps are based on market
prices of comparable investments.
BOOK FAIR BOOK FAIR
VALUE VALUE VALUE VALUE
NOTES 2000 2000 1999 1999
----- -------- -------- -------- --------
LM LM LM LM
PRIMARY FINANCIAL INSTRUMENTS HELD OR ISSUED TO
FINANCE THE GROUP'S OPERATIONS:
Short term borrowings.................................... (12.6) (12.6) (61.3) (61.3)
Long term borrowings..................................... (2,118.7) (2,188.7) (2,124.5) (2,321.0)
Preference shares........................................ (206.6) (157.5) (206.6) (254.8)
Other financial liabilities.............................. (24.8) (24.8) (22.5) (22.5)
Long term debtors........................................ 3.4 3.4 10.4 10.4
Current asset investments................................ 19 429.0 429.0 591.3 591.3
Cash at bank and in hand................................. 34.0 34.0 21.0 21.0
Bank loans and overdrafts................................ 20(a) (5.8) (5.8) (0.6) (0.6)
-------- -------- -------- --------
(1,902.1) (1,923.0) (1,792.8) (2,037.5)
DERIVATIVE FINANCIAL INSTRUMENTS HELD TO MANAGE THE
INTEREST RATE AND CURRENCY PROFILE AND MATCHED BY
PRIMARY FINANCIAL INSTRUMENTS:
Interest rate swaps...................................... -- (6.3) -- (10.5)
Combined interest rate and forward foreign currency swaps -- (59.2) -- (51.1)
-------- -------- -------- --------
(1,902.1) (1,988.5) (1,792.8) (2,099.1)
DERIVATIVE FINANCIAL INSTRUMENTS HELD TO MANAGE THE
INTEREST RATE PROFILE AND NOT MATCHED BY A PRIMARY
FINANCIAL INSTRUMENT:
Interest rate swaps...................................... -- (3.5) -- (8.1)
-------- -------- -------- --------
(1,902.1) (1,992.0) (1,792.8) (2,107.2)
======== ======== ======== ========
The fair value of derivative financial instruments matched by primary
financial instruments relates to long term borrowings with a book value of
L673.4m (1999 L674.5m) which have been included within the primary financial
instruments issued to finance the group's operations at a fair value of L637.6m
(1999 L676.3m), which is the redemption value of those borrowings.
F-104
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(M) LOSSES ON DERIVATIVE FINANCIAL INSTRUMENTS
The fair value of losses on derivative financial instruments are not
recognised in the financial statements. These instruments are held to manage
the group's interest rate and currency exposures and the resultant fixed
interest charges are made in the accounting periods to which they relate. The
table below analyses the composition of the fair value losses (note 24(l)).
UNRECOGNISED TOTAL
NET GAINS/LOSSES 2000
---------------------
LM
Losses on hedges at 1 April 1999................................... (69.7)
Gains not included in 1999/2000 income............................. 0.7
-----
Losses on hedges at 31 March 2000.................................. (69.0)
=====
Of which:
Losses expected to be included in 2000/01 income................... (0.6)
Losses expected to be included in 2001/02 income or later years.... (2.9)
Losses not expected to be included in 2001/02 income or later years (65.5)
-----
(69.0)
=====
25. CAPITAL COMMITMENTS
GROUP
2000 1999
----- -----
LM LM
Contracted for but not provided in the financial statements 155.4 182.5
===== =====
In order to meet additional quality and service standards, together with
growth and new demands, the group has capital investment obligations over the
next five years amounting to approximately L1.13 billion at current prices in
the regulated water and sewerage business and approximately L250 million at
current prices, within the regulated electricity distribution business.
26. LEASING COMMITMENTS
At 31 March 2000 there were revenue commitments, in the ordinary course of
business in the next year relating to the payment of rentals on non-cancellable
operating leases expiring:
GROUP
LAND AND BUILDINGS OTHERS
------------------ ---------
2000 1999 2000 1999
---- ---- ---- ----
LM LM LM LM
Within one year........... 0.5 0.9 2.9 4.7
Between two and five years 1.4 2.8 4.2 2.6
After five years.......... 3.5 2.6 0.3 3.0
--- --- --- ----
5.4 6.3 7.4 10.3
=== === === ====
F-105
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
COMPANY
LAND AND BUILDINGS OTHERS
------------------ ---------
2000 1999 2000 1999
---- ---- ---- ----
LM LM LM LM
Within one year. 0.2 0.2 -- --
After five years 0.1 0.1 -- --
--- --- -- --
0.3 0.3 -- --
=== === == ==
27. PROVISIONS FOR LIABILITIES AND CHARGES
GROUP COMPANY
---------- ---------
NOTES 2000 1999 2000 1999
----- ---- ----- ---- ----
LM LM LM LM
Deferred taxation....... (a) 15.0 -- -- --
Group insurance funds... (b) 15.1 12.9 -- --
Reorganisation provision (c) 26.9 47.9 0.4 0.7
Pensions provision...... (d) 2.8 2.8 1.5 1.2
Power purchase provision (e) -- 65.7 -- --
Other provisions........ (f) 20.1 13.8 0.5 0.5
---- ----- --- ---
79.9 143.1 2.4 2.4
==== ===== === ===
(A) DEFERRED TAXATION
GROUP
AMOUNT PROVIDED AMOUNTS UNPROVIDED
--------------- -----------------
2000 1999 2000 1999
---- ---- ----- -----
LM LM LM LM
Tax effect of timing differences:
Excess of tax allowances over depreciation. -- -- 371.3 355.3
Other timing differences................... -- -- (8.7) (20.5)
---- -- ----- -----
-- -- 362.6 334.8
Capital gains rolled over..................... 15.0 -- 7.7 0.2
Earnings retained overseas.................... -- -- 4.3 3.3
---- -- ----- -----
15.0 -- 374.6 338.3
==== == ===== =====
F-106
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
COMPANY
AMOUNT UNPROVIDED
-------------------
2000 1999
---- ----
LM LM
Tax effect of timing differences:
Excess of tax allowances over depreciation.............. 0.2 0.2
Other timing differences................................ (0.6) (0.4)
---- ----
(0.4) (0.2)
==== ====
(B) GROUP INSURANCE FUNDS
GROUP COMPANY
----- -------
LM LM
At 1 April 1999............................................ 12.9 --
Premiums................................................... 5.7 --
Claims..................................................... (3.1) --
Released to profit and loss account........................ (0.4) --
---- --
At 31 March 2000........................................... 15.1 --
==== ==
Cover against certain risks is provided by Brecon Insurance Company Limited,
a wholly owned subsidiary undertaking of the group.
(C) REORGANISATION PROVISION
NOTE GROUP COMPANY
---- ----- -------
LM LM
At 1 April 1999....................................... 47.9 0.7
Charged to profit and loss account.................... 5 35.1 0.5
Released to profit and loss account................... 5 (10.2) --
Utilised.............................................. (45.9) (0.8)
----- ----
At 31 March 2000...................................... 26.9 0.4
===== ====
The reorganisation provision includes severance, related pension costs and
property costs for restructuring initiatives which will be completed within the
next 24 months.
(D) PENSIONS PROVISION
GROUP COMPANY
----- -------
LM LM
At 1 April 1999............................................ 2.8 1.2
Charged to profit and loss account......................... 0.4 0.3
Utilised................................................... (0.4) --
---- ---
At 31 March 2000........................................... 2.8 1.5
==== ===
This provision relates to unfunded directors pensions (note 6 (d)(iv)) and
the "Barber" provisions which are expected to be utilised within the next 24
months.
F-107
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(E) POWER PURCHASE PROVISION
NOTE GROUP COMPANY
---- ----- -------
LM LM
At 1 April 1999.......................................... 65.7 --
Utilised................................................. 4 (6.4) --
Released to profit and loss account on disposal of supply
business............................................... 39 (59.3) --
----- --
At 31 March 2000......................................... -- --
===== ==
(F) OTHER PROVISIONS
GROUP COMPANY
----- -------
LM LM
At 1 April 1999................................................. 13.8 0.5
Charged to profit and loss account.............................. 10.1 --
Utilised........................................................ (3.8) --
---- ---
At 31 March 2000................................................ 20.1 0.5
==== ===
These provisions principally relate to leasehold property provisions,
onerous contracts, uninsured losses and other claims arising which are expected
to be utilised within the next 16 years.
28. ACCRUALS AND DEFERRED INCOME
GROUP
LM
At 1 April 1999...................................................... 155.3
Receivable during the year........................................... 10.5
Released to profit and loss account.................................. (6.0)
-----
At 31 March 2000..................................................... 159.8
=====
Deferred income represents grants and customer contributions received in
respect of investment in non-infrastructure fixed assets. These grants are
amortised to the profit and loss account over the estimated useful economic
life of the related assets.
F-108
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
29. CALLED UP SHARE CAPITAL
2000 1999
----- -----
LM LM
AUTHORISED:
166,666,667 ordinary shares of 120p each (1999 166,666,667)........ 200.0 200.0
209,000,000 cumulative redeemable preference shares (7.875% net) of
L1 each (redeemable 31 July 2013) (1999 209,000,000)............. 209.0 209.0
----- -----
409.0 409.0
===== =====
ALLOTTED, CALLED UP AND FULLY PAID:
154,710,591 ordinary shares of 120p each (1999 151,018,332)........ 185.6 181.2
207,181,776 cumulative redeemable preference shares (7.875% net) of
L1 each (redeemable 31 July 2013) (1999 207,181,776)............. 207.2 207.2
----- -----
392.8 388.4
===== =====
All cumulative redeemable preference shares are redeemable at par on 31 July
2013. These shares are non-voting and have a preferential right to return of
capital on a winding up.
Ordinary shares were issued in the year resulting from the exercise of share
options under the Hyder and South Wales Electricity plc employee sharesave and
executive share option schemes at prices between 354p and 676p per share.
In total 3,692,259 ordinary shares, with an aggregate nominal value of L4.4m
were issued in the year. The cash consideration received in respect of the
issue of 5,957 ordinary shares was L37,000. Included within the total are
3,686,302 ordinary shares with an aggregate nominal value of L4.4m issued in
relation to the scrip dividend plan for which no cash consideration was
received.
30. EMPLOYEE SHARE SCHEMES
(A) HYDER PLC SHARE SCHEMES
The company has four Inland Revenue approved share option schemes for its
employees and those of subsidiary undertakings. There is also an unapproved
scheme (the Hyder overseas share plan) which extends share scheme arrangements
for the benefit of overseas employees resident outside of the United Kingdom.
The employee sharesave scheme is savings related and the share options are
exercisable within six months of completion of a three, five or seven year save
as you earn contract. Employee sharesave options are fixed at the closing mid
market value on the day preceding the date of grant less 20% discount. The
executive share option scheme is a discretionary scheme for senior employees
under which options are granted at fixed prices at the closing mid market value
on the day preceding the date of grant. Executive share options granted after
July 1993 are performance related and can only be exercised if the increase in
the share price of an ordinary share exceeds the increase in the Retail Prices
Index plus 2% per annum compound (pro rata for any period of less than one
year) in the period between the date of grant and the exercise date. All
executive share options are exercisable between three and ten years from the
date of grant. No new options may be granted to executive directors under this
scheme.
F-109
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Options granted but not yet exercised under these schemes at 31 March 2000
together with their exercise prices and dates are shown below:
OPTION NUMBER OF 120P
PRICE PER ORDINARY SHARES
DATE OPTION SHARE -------------------
GRANTED NORMAL DATE OF EXERCISE (PENCE) 2000 1999
-------------- ------------------------------ --------- --------- ---------
EMPLOYEE SHARESAVE SCHEME........ December 1992 March 2000 - August 2000 425 - 427 103,830 321,180
September 1994 October 1999 - March 2000 522 - 525 -- 358,333
September 1994 October 2001 - March 2002 522 - 525 143,096 165,911
December 1994 February 2000 - August 2000 522 - 525 55,240 243,724
December 1994 February 2002 - August 2002 522 - 525 87,153 107,021
July 1997 September 2000 - February 2001 650 525,180 734,208
July 1997 September 2002 - February 2003 650 1,780,396 2,477,291
--------- ---------
2,694,895 4,407,668
--------- ---------
EXECUTIVE SHARE OPTION SCHEME.... July 1991 July 1994 - July 2001 354 23,021 24,049
July 1993 July 1996 - July 2003 563 55,909 55,909
August 1993 August 1996 - August 2003 648 13,937 21,146
January 1994 January 1997 - January 2004 716 151,442 151,442
January 1995 January 1998 - January 2005 676 16,928 21,857
--------- ---------
261,237 274,403
--------- ---------
OVERSEAS SHARE PLAN.............. October 1997 November 2000 - April 2001 841 38,749 67,280
October 1997 November 2002 - April 2003 841 14,424 32,910
--------- ---------
53,173 100,190
--------- ---------
3,009,305 4,782,261
========= =========
No options were granted during the year ended 31 March 2000. All options and
rights over Hyder plc ordinary shares held under Inland Revenue approved share
schemes can be exercised early in certain exceptional circumstances such as
retirement or redundancy.
During the year ended 31 March 1999 two Inland Revenue approved profit
sharing schemes were established, one for the benefit of staff employed by
Hyder Utilities (the utilities scheme) and a separate scheme for the benefit of
employees of Hyder plc (the plc scheme). The number of Hyder ordinary shares
appropriated under these schemes in July 1998 and held in trust at 31 March
2000 were 146,263 (1999 72,211) ordinary shares under the utilities scheme and
3,748 (1999 1,688) ordinary shares under the plc scheme. All shares are held in
trust under the rules of the schemes. A further appropriation of shares will
take place in July 2000 subject to scheme targets and eligibility criteria
being met.
(B) HYDER PLC LONG TERM INCENTIVE PLAN (L-TIP)
The company L-Tip is available to executive directors and selected senior
executives. Full details of this scheme are set out in note 6. The ordinary
shares which are conditionally allocated under the L-Tip are purchased in the
market by an employee benefit trust with funds allocated by the company. The
trustees have waived dividends on the shares held.
A second L-Tip was established in 1999 for the benefit of a director, J M
James, who does not participate in the main L-Tip. Details are disclosed in
note 6.
F-110
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(C) QUALIFYING EMPLOYEE SHARE OPTION TRUST (QUEST)
In March 1998 the company established a qualifying employee share option
trust (Quest) as a vehicle to procure ordinary shares in Hyder plc to meet in
part the obligations of the company pursuant to valid exercises of options
under the rules of the Hyder and South Wales Electricity sharesave schemes. At
31 March 2000 Hyder Share Scheme Trustee (2) Limited, as trustee, held
3,261,565 ordinary shares (1999 3,437,499) with a value, based on the average
closing price of the shares in the thirty days up to 7 July, being the latest
practicable date prior to the directors' approving the financial statements, of
L10.4m (1999 market value L27.0m). If the shares are transferred at this value
otherwise than for a qualifying purpose of the Quest, an income tax charge of
L5.3m will be payable by Hyder Share Scheme Trustees (2) Limited.
The accounts include the shares held by the Quest, which are included as
fixed asset investments. Under the rules of the Quest dividends have been
waived by the trustee. The expenses of Quest which are borne by the group are
expensed as incurred. The purchase of shares by Hyder Share Scheme Trustee (2)
Limited as trustee was financed by loans from Hyder plc.
Details of share options outstanding under the sharesave schemes are stated
in notes 30(a) above.
31. SHARE PREMIUM ACCOUNT
GROUP COMPANY
----- -------
LM LM
At 1 April 1999............................................................. 137.4 137.4
Nominal value of ordinary shares issued under scrip dividend in lieu of cash
dividend (note 29)........................................................ (4.4) (4.4)
----- -----
At 31 March 2000............................................................ 133.0 133.0
===== =====
32. RESERVES
(A) PROFIT AND LOSS ACCOUNT
GROUP COMPANY
----- -------
LM LM
At 1 April 1999........................................................ 370.8 443.5
Profit/(loss) retained for the year.................................... 48.1 (152.3)
Goodwill written back on disposal...................................... 84.0 --
Scrip dividend issued in lieu of cash dividend......................... 21.5 21.5
Foreign currency translation losses.................................... (1.3) (0.2)
Reserves adjustment on acquisition of additional interest in subsidiary (0.7) --
----- ------
At 31 March 2000....................................................... 522.4 312.5
===== ======
The cumulative goodwill written off directly to reserves is L544.3m (1999
L628.3m).
In accordance with the group's accounting policy, Lnil of net exchange
differences (1999 L0.2m net gains) on foreign currency loans which match
investments have been offset in reserves.
F-111
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(B) CAPITAL RESERVE
GROUP COMPANY
----- -------
LM LM
At 1 April 1999 and 31 March 2000 -- 9.6
== ===
The capital reserve arose on the acquisition of South Wales Electricity plc
and comprised the fair value of the options granted by the company to South
Wales Electricity plc share option holders less the option price to be received
by the company on the exercise of those options.
(C) INVESTMENT REVALUATION RESERVE
GROUP COMPANY
----- -------
LM LM
At 1 April 1999....... 1.2 --
Revaluations (note 15) 1.5 --
--- --
At 31 March 2000...... 2.7 --
=== ==
(D) CAPITAL REDEMPTION RESERVE
On 30 December 1994 the group and company created a capital redemption
reserve of L1 following the redemption at par of the special rights redeemable
preference share of L1.
33. EQUITY MINORITY INTEREST
GROUP COMPANY
----- -------
LM LM
At 1 April 1999.................... 2.6 --
Adjustment to fair value of assets. (0.4) --
Purchase of minority interest...... (1.5) --
Recognition of results for the year 0.2 --
Currency translation differences... (0.2) --
---- --
At 31 March 2000................... 0.7 --
==== ==
F-112
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
34. NET CASH INFLOW FROM OPERATING ACTIVITIES
2000 1999 1998
----- ----- -----
LM LM LM
CONTINUING OPERATIONS:
Operating profit............................................... 164.1 270.6 239.6
Non cash element of exceptional items (excluding reorganisation
costs)....................................................... 73.3 -- --
Depreciation of tangible fixed assets.......................... 136.8 122.8 100.4
Amounts written off tangible fixed assets...................... -- 7.1 1.5
Amounts provided on intangible fixed assets and fixed asset
investments.................................................. 1.1 2.0 1.5
Amortisation of grants and contributions....................... (6.0) (5.9) (5.5)
Loss/(profit) on sale of fixed assets.......................... 0.5 -- (0.8)
Net increase in stocks......................................... (1.7) (1.9) (0.6)
Net (increase)/decrease in debtors............................. (34.0) 1.2 (12.2)
Net increase/(decrease) in creditors........................... 46.5 4.0 (13.0)
Contribution from/(to) insurance fund.......................... 2.3 0.1 (2.8)
Reorganisation provisions...................................... (20.5) (11.2) 10.6
Contributions to pension fund.................................. -- (0.2) (0.1)
Other provisions--storm damage................................. -- (6.5) --
Other provisions............................................... 6.3 0.4 --
----- ----- -----
Net cash inflow from continuing operating activities........... 368.7 382.5 318.6
===== ===== =====
DISCONTINUED OPERATIONS:
Operating (loss)/profit........................................ (3.7) 26.0 5.1
Non cash element of exceptional items (excluding reorganisation
costs)....................................................... 12.8 -- --
Depreciation of tangible fixed assets.......................... 3.6 1.6 0.9
Net increase in stocks......................................... (0.3) -- --
Net decrease/(increase) in debtors............................. 1.1 (29.0) (11.5)
Net increase in creditors...................................... 1.9 9.9 12.8
Contribution (to)/from insurance fund.......................... (0.1) 0.1 --
Reorganisation provisions...................................... (0.5) -- (0.9)
Power purchase provision release............................... (6.4) (7.3) --
Other provisions............................................... (0.5) -- --
----- ----- -----
Net cash inflow from discontinued operating activities......... 7.9 1.3 6.4
----- ----- -----
Net cash inflow from operating activities...................... 376.6 383.8 325.0
===== ===== =====
F-113
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
Debtors have increased in the continuing operations in 2000 principally due
to amounts owing to the electricity distribution business by the energy supply
business which in 1999 and 1998 were intercompany balances and eliminated in
the group accounts.
35. ANALYSIS OF NET DEBT
(A) MOVEMENTS IN THE YEAR
CASH LESS BANK CURRENT ASSET DEBT AND
OVERDRAFTS INVESTMENTS FINANCE LEASES TOTAL
-------------- ------------- -------------- --------
LM LM LM LM
At 1 April 1999................. 20.4 591.3 (2,185.8) (1,574.1)
Consolidated cashflow statement. 7.8 (162.0) 55.7 (98.5)
Bond issue costs written back... -- -- (0.6) (0.6)
Currency translation differences -- (0.3) (0.6) (0.9)
---- ------ -------- --------
At 31 March 2000................ 28.2 429.0 (2,131.3) (1,674.1)
==== ====== ======== ========
(B) YEAR END RECONCILIATION
NOTE 2000 1999
---- -------- --------
LM LM
Loans and finance lease obligations:
Amounts falling due within one year......... 20(a) (12.6) (61.3)
Amounts falling due after more than one year 20(b) (2,118.7) (2,124.5)
-------- --------
35(a) (2,131.3) (2,185.8)
Current asset investments................... 19 429.0 591.3
Cash at bank and in hand.................... 34.0 21.0
Bank loans and overdrafts................... 20(a) (5.8) (0.6)
-------- --------
35(a) (1,674.1) (1,574.1)
======== ========
36. ANALYSIS OF CHANGES IN FINANCING IN THE YEAR
SHARE CAPITAL LOANS & FINANCE
(INCLUDING PREMIUM) LEASE OBLIGATIONS
------------------- ----------------
2000 1999 2000 1999
----- ----- ------- -------
LM LM LM LM
At 1 April...................................... 525.8 525.3 2,185.8 1,575.1
New loans and bonds............................. -- -- 2.0 529.4
New finance leases.............................. -- -- -- 92.1
Loans acquired with subsidiaries................ -- -- -- 3.4
Loan notes issued on acquisition of subsidiaries -- -- -- 1.7
Loan repayments................................. -- -- (57.5) (9.0)
Finance lease repayments........................ -- -- (0.2) (0.5)
Bond issue costs written back................... -- -- 0.6 0.1
Proceeds from the issue of ordinary shares...... -- 0.5 -- --
Expenses of issuing bonds....................... -- -- -- (6.6)
Currency translation difference................. -- -- 0.6 0.1
----- ----- ------- -------
At 31 March..................................... 525.8 525.8 2,131.3 2,185.8
===== ===== ======= =======
F-114
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
37. RECONCILIATION OF NET CASH FLOW TO INCREASE IN NET DEBT
NOTE 2000 1999
---- -------- --------
LM LM
Increase in cash as per cashflow statement................... 7.8 28.9
Decrease/(increase) in loans and finance lease obligations... 35(a) 55.7 (605.4)
(Decrease)/increase in liquid resources held as current asset
investments................................................ 35(a) (162.0) 289.7
-------- --------
Increase in net debt resulting from cash flows............... (98.5) (286.8)
Acquired with subsidiaries................................... -- (3.4)
Issued on acquisition of subsidiaries........................ -- (1.7)
Bond issue costs written back................................ (0.6) (0.1)
Currency translation differences............................. 35(a) (0.9) 0.1
-------- --------
Increase in net debt......................................... (100.0) (291.9)
At 1 April................................................... (1,574.1) (1,282.2)
-------- --------
At 31 March.................................................. (1,674.1) (1,574.1)
======== ========
38. ACQUISITION
During the year the group increased its shareholding in AcerPlan GmbH from
56% to 89%. These operations have been integrated into the continuing
activities of the group. The additional shareholding of 33% resulted from a
further consideration of L1.7m, of which L0.2m is deferred consideration.
39. DISPOSALS OF GROUP OPERATIONS
On 17 February 2000 the group sold SWALEC Gas Limited and the electricity
supply business of South Wales Electricity plc for a consideration of L106.8m.
On 31 March 2000 the group also disposed of Environmental Laboratories, an
unincorporated division of Hyder Consulting Limited, for a consideration of
L11.4m of which the final payment of L11.2m was received on 7 April 2000. The
values of the assets disposed of were as follows:
LM
-----
Tangible fixed assets........................ 13.9
Debtors...................................... 102.7
Work in progress............................. 1.1
Cash......................................... 1.0
Creditors.................................... (84.1)
Provisions arising on disposal............... 1.3
Tangible fixed assets written off............ 8.5
Transaction costs............................ 2.1
Goodwill previously written off to reserves.. 84.0
Power purchase provision released on disposal (59.3)
-----
71.2
Profit on disposal........................... 47.0
-----
118.2
=====
CONSIDERATION:
Cash received in the year.................... 107.0
Cash received on 7 April 2000................ 11.2
-----
118.2
=====
F-115
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
The net inflow of cash arising from the above disposals was as follows:
LM
-----
Cash received.... 107.0
Cash released.... (1.0)
Transaction costs (2.1)
-----
103.9
=====
The amounts included in the consolidated profit and loss account and
cashflows up to the date of disposal in respect of the energy supply business
and Environmental Laboratories are shown in notes 2, 4 and 34.
The deferred tax charge of L15.0m in respect of the above disposals relates
to capital gains rolled over (note 27(a)).
40. DIRECTORS' AND OFFICERS' LOANS AND TRANSACTIONS
No loans or credit transactions with any directors, officers or connected
persons subsisted during the year or were outstanding at the end of the year.
41. PENSION SCHEMES
The group operates a number of pension schemes both in the UK and overseas.
The assets of each pension scheme are held separately from the assets of the
group and are administered by trustees. The principal schemes are defined
benefit schemes in the UK--the Hyder Water Pension Scheme (HWPS), the Water
Mirror Image Pension Scheme (WMIS), the Electricity Supply Pension Scheme
(ESPS) and the Acer Group Pension Scheme (AGPS).
The employer's contributions and pension cost under the accounting standard
Statement of Standard Accounting Practice No. 24 "Accounting for Pension Costs"
(SSAP24) for the HWPS and WMIS has been assessed in accordance with the advice
of William M. Mercer Limited, consulting actuaries, using the projected unit
method for HWPS and the attained age method for WMIS. For this purpose the
actuarial assumptions adopted are based upon investment growth of 6.5% per
annum, pay growth of 4.5% per annum and increases to pensions in payment and
deferred pensions of 3% per annum.
The last actuarial valuations for HWPS and WMIS were carried out as at 31
March 1998 with the market values being L324.6m and L99.9m respectively. Using
the assumptions adopted for SSAP 24, the actuarial value of assets represented
113% for HWPS and 118% for WMIS of the value of the accrued benefits after
allowing for expected future earnings increases. In deriving the pension cost
under SSAP24 the surpluses in HWPS and WMIS are spread over the future working
lifetime of employees.
The employer's contributions and pension cost for the South Wales section of
the ESPS has been assessed in accordance with advice from Bacon and Woodrow,
consulting actuary, at 31 March 1998, using the attained age actuarial method.
For this purpose the principal actuarial assumptions adopted were an investment
growth of 8.5% per annum, pay growth of 6% per annum and increases to pensions
in payment of 4.5% per annum.
The latest actuarial valuation was carried out at 31 March 1998, with the
market value of the assets being L526.3m. Using the assumptions adopted for
SSAP24 the actuarial value of the assets represented 110% of the
F-116
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
value of the accrued benefits after allowing for expected future earnings
increases. In deriving the pension cost under SSAP24 the surplus in the scheme
is being recognised as a reduction to pension cost over the future working
lifetime of the employees and to cover short term early retirement costs.
The employer's contributions and pension cost for AGPS, being the principal
UK scheme for Hyder Consulting Group Limited, has been assessed in accordance
with the advice of Buck Consultants Limited using the projected unit method.
For this purpose the main actuarial assumptions used are based upon investment
growth of 7.5% per annum, pay growth of 4.5% per annum, and increases to
pensions in payment of 3.5% per annum.
The latest actuarial valuation was carried out as at 1 May 1999 with the
market value of the assets being L55.0m. Using the assumptions adopted for
SSAP24 the actuarial value of the assets represented 94% of the value of the
accrued benefits after allowing for expected future earnings increases. In
deriving the pension cost under SSAP24 the deficit in the scheme is being
spread over the future working lifetime of employees by way of increased
employer's contribution rates.
The total group pension cost for the period was L14.7m (1999 L14.5m). A
prepayment of pension costs of L8.5m (1999 L6.6m) is included in note 18 within
prepayments and accrued income.
As a consequence of changes made by the Finance Act 1989 the group is unable
to provide fully for approved pension for some executive directors who have
joined the group since 1989. The group has therefore made alternative
arrangements in these cases. Provision for the cost of unfunded pension is
included in the charge for the period on a basis consistent with SSAP 24. These
arrangements will not result in any individual executive director receiving any
greater benefit than would have applied if the full approved provision had been
possible.
42. CONTINGENT LIABILITIES
GROUP
In accordance with normal commercial practice, various group companies have
provided a number of third party guarantees in relation to trading or
investment obligations arising from contracts entered into in the normal course
of business. In addition guarantees of L12m (1999 Lnil) have been provided in
respect of third party debt obligations.
COMPANY
The company has provided guarantees in respect of finance lease and loan
facilities granted to its subsidiary Dwr Cymru Cyfyngedig amounting to L464.8m
(1999 L500.4m). The loan and finance lease facilities are fully drawn down and
therefore no further guarantees are required.
The company is a participant in a cash pooling arrangement operated by
National Westminster Bank Plc in the United Kingdom. The company has guaranteed
the bank overdraft balances of the participating companies, all of which are
subsidiaries of the company, subject to a maximum amount equal to the company's
own cash balance with the bank. At 31 March 2000 the overdrafts in subsidiary
companies in the cash pooling arrangement amounted to L29.9m (1999 L29.8m).
The company, as ultimate holding company, has provided third party
guarantees of L35.5m (1999 L18.8m) in relation to investment obligations
entered into by subsidiary companies. The company has also provided a number of
third party guarantees in relation to contractual obligations entered into by
subsidiary companies in the normal course of business.
F-117
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
43. ELAN AQUEDUCT
In 1984 Welsh Water Authority entered into a conditional sale and purchase
agreement with Severn Trent Water Authority for the sale of the aqueduct and
associated works by which the bulk supply to Severn Trent reservoirs is
conveyed.
The sum of L31.7m, representing the consideration for the conditional sale,
has been invested in a trust fund. The principal function of the fund was to
provide an income to Welsh Water Authority, whilst preserving the capital value
of the fund in real terms. Welsh Water Authority's interest in this fund was
vested in Dwr Cymru Cyfyngedig under the provisions of the Water Act 1989. The
assets of the fund are not included in these financial statements.
44. PRINCIPAL GROUP UNDERTAKINGS
SHAREHOLDING
-------------------
COUNTRY OF
INCORPORATION,
REGISTRATION AND
OPERATION DIRECTLY INDIRECTLY
----------------- -------- ----------
% %
SUBSIDIARY UNDERTAKINGS
UTILITY ACTIVITIES
Hyder Utilities (Holdings) Limited.................. England and Wales 100
REGULATED WATER AND SEWERAGE ACTIVITIES
Dwr Cymru Cyfyngedig................................ England and Wales 100
Welsh Water Utilities Finance PLC................... England and Wales 100
Hyder Utilities (Operations) Limited................ England and Wales 50
REGULATED ELECTRICITY DISTRIBUTION ACTIVITIES
South Wales Electricity plc (distribution business). England and Wales 100
Hyder Utilities (Operations) Limited............ England and Wales 50
MANAGED SERVICES ACTIVITIES
Hyder Services Limited.............................. England and Wales 100
INFRASTRUCTURE ACTIVITIES
Hyder Consulting Group Limited...................... England and Wales 100
Hyder Consulting Limited........................ England and Wales 100
Hyder Consulting (Pte) Limited.................. Singapore 100
Hyder Australia Pty Limited..................... Australia 100
Hyder Consulting Limited........................ Hong Kong 100
Freeman Fox Group Limited....................... Hong Kong 100
Hyder Industrial Group Limited...................... England and Wales 100
Hyder Industrial Limited........................ England and Wales 100
Hyder Holdings Inc.............................. USA 100
Hyder Investments Limited........................... England and Wales 100
Hyder Overseas Investments Limited.............. England and Wales 100
Hyder Infrastructure Management Limited............. England and Wales 100
Phoenix Electrical Company Limited.............. England and Wales 100
OTHER ACTIVITIES
Brecon Insurance Co Limited......................... Guernsey 100
F-118
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
JOINT VENTURES AND ASSOCIATED UNDERTAKINGS
TOTAL JOINT
VENTURE/ASSOCIATE
COUNTRY OF COMPANY'S GROUP
INCORPORATION EQUITY SHAREHOLDING
----------------- ----------------- ------------
JOINT VENTURES
UK Highways M40 (Holdings) plc........ England and Wales
Ordinary shares of L1 each......... L11.0m 44.0%
UK Highways A55 (Holdings) Limited.... England and Wales
Ordinary shares of L1 each......... L0.5m 45.0%
Subordinated loan stock............ L9.3m 45.0%
City Greenwich Lewisham Link Rail plc. England and Wales
Ordinary shares of L1 each......... L1.5m 40.0%
Loan stock......................... L11.0m 40.0%
Tieyhtio Nelostie Oy.................. Finland
Shares of Fmk 100 each............. Fmk 50,000 43.0%
Loan stock......................... Fmk 50m 43.0%
Laing Hyder plc....................... England and Wales
Ordinary shares of L1 each......... L4.0m 50.0%
Loan stock......................... L0.5m 50.0%
CountyRoute Limited................... England and Wales
Ordinary shares.................... L0.5m 50.0%
Loan stock......................... L9.4m 50.0%
Citylink Telecommunications (Holdings)
Limited............................ England and Wales
Ordinary shares.................... L10.7m 19.5%
Loan stock......................... L32.2m 19.5%
Coastal Clearwater (Holdings) Limited. England and Wales
Ordinary shares.................... L0.1m 50.0%
Loan stock......................... L0.9m 50.0%
ASSOCIATED UNDERTAKINGS
The China Water Co Ltd................ Cayman Islands
Shares of US$0.50 each............. US$64.8m 20.0%
The above companies are franchise operators within the highways, railways
and telecommunications sectors, with the exception of The China Water Co Ltd
and Coastal Clearwater (Holdings) Limited which are infrastructure investment
businesses operating in the Chinese and UK water and waste water sectors and
Laing Hyder plc, which is an infrastructure investment business operating in
the UK Public Private Partnership accommodation sector.
All the above companies are, in the opinion of the directors, material to
the group. A complete list of all subsidiary, joint venture and associate
companies is available from the Company Secretary.
F-119
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
45. SUMMARY OF DIFFERENCES BETWEEN UK AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES ("GAAP")
The Group's consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United Kingdom
("UK GAAP"). Such principles differ in certain respects from generally accepted
accounting principles in the United States ("US GAAP"). A summary of principal
differences applicable to the group is set out below. While this is not a
comprehensive summary of all differences between UK and US GAAP, other
differences would not have a significant effect on the consolidated net income
or shareholders equity of the group.
RECONCILIATION OF PROFIT ON ORDINARY ACTIVITIES AFTER TAXATION UNDER UK GAAP
TO NET INCOME UNDER US GAAP
EXPLANATION
REFERENCE 2000 1999
----------- ------ -----
LM LM
PROFIT ON ORDINARY ACTIVITIES AFTER TAXATION UNDER UK GAAP.................. 74.8 197.4
Less: Equity minority interest.............................................. (xi) (0.2) (-- )
Dividend on redeemable preferred stock................................. (x) (16.4) (16.4)
------ -----
NET INCOME BEFORE US GAAP ADJUSTMENTS 58.2 181.0
US GAAP adjustments:
Depreciation of infrastructure assets.................................... (i) (13.0) (11.5)
Pensions................................................................. (ii) 19.9 40.9
Goodwill amortization--continuing operations............................. (iii) (20.0) (19.9)
Goodwill amortization--discontinued operations........................... (iii) (1.8) (2.1)
Profit on disposal of business and investments in associates............. (iv) 8.6 0.6
Impairment of goodwill................................................... (v) (432.0) --
Deferred taxation--application of FAS 109................................ (vi) (17.6) (3.6)
Investment properties--depreciation...................................... (vii) (0.2) (0.2)
Capitalised interest..................................................... (viii) 33.5 31.0
Depreciation on capitalised interest..................................... (viii) (5.5) (4.4)
Own shares--impairment in value.......................................... (xii) 10.0 --
Business development costs............................................... (xiii) (3.3) (0.8)
Deferred compensation.................................................... (xv) (1.5) (1.6)
Restructuring costs...................................................... (xvi) (5.8) (5.0)
Financial instruments.................................................... (xvii) 4.6 1.4
Deferred tax on US GAAP adjustments...................................... (6.4) (14.7)
------ -----
NET (LOSS)/INCOME UNDER US GAAP............................................. (372.3) 191.1
====== =====
RECONCILIATION OF NET (LOSS)/INCOME IN ACCORDANCE WITH US GAAP
Net (loss)/income from continuing operations............................. (413.1) 172.4
Net (loss)/income from discontinued operations (net of tax benefit and
expense: L0.7m and L8.4m, respectively)................................ (xviii) (1.5) 18.7
Net income from sale of discontinued operations (net of tax
expense: L13.3m)....................................................... (xviii) 42.3 --
------ -----
Net (loss)/income under US GAAP.......................................... (372.3) 191.1
====== =====
F-120
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
EARNINGS PER SHARE
EXPLANATION
REFERENCE 2000 1999
----------- ------- -------
(PENCE) (PENCE)
AMOUNTS IN ACCORDANCE WITH US GAAP
Basic earnings per ordinary share:.. (xix)
Continuing operations............ (276.6) 117.5
Discontinued operations.......... 27.3 12.7
Net (loss)/income................... (249.3) 130.2
Diluted earnings per ordinary share: (xix)
Continuing operations............ (276.6) 116.7
Discontinued operations.......... 27.3 12.6
Net (loss)/income................... (249.3) 129.3
RECONCILIATION OF SHAREHOLDERS' EQUITY
EXPLANATION
REFERENCE 2000 1999
----------- ------- -------
LM LM
NET ASSETS UNDER UK GAAP........................ 1,051.6 900.4
Less: Equity minority interests................. (xi) (0.7) (2.6)
------- -------
SHAREHOLDERS' FUNDS UNDER UK GAAP............... 1050.9 897.8
US GAAP adjustments:
Infrastructure assets........................... (i) (83.5) (70.5)
Pensions........................................ (ii) 189.0 169.1
Goodwill........................................ (iii) 7.5 536.7
Deferred taxation............................... (vi) (457.1) (433.4)
Investment properties........................... (vii) (3.6) (1.9)
Capitalised interest............................ (viii) 182.3 148.8
Depreciation on capitalised interest............ (viii) (21.7) (16.2)
Ordinary dividends.............................. (ix) -- 49.7
Redeemable preferred stock...................... (x) (206.6) (206.6)
Own shares...................................... (xii) (10.3) (21.7)
Business development costs...................... (xiii) (4.1) (0.8)
Listed investments.............................. (xiv) 6.4 16.7
Deferred compensation--cumulative expense....... (xv) 4.8 3.3
Deferred compensation--unrecognized expense..... (xv) 2.4 3.9
Deferred compensation--increase to share premium (xv) (7.2) (7.2)
Restructuring costs............................. (xvi) 2.0 7.8
Financial instruments........................... (xvii) (3.5) (8.1)
------- -------
SHAREHOLDERS' FUNDS UNDER US GAAP............... 647.7 1,067.4
======= =======
(I) DEPRECIATION OF INFRASTRUCTURE ASSETS
Under UK GAAP, depreciation is not provided on infrastructure assets which
increases capacity or enhances the network because the network of systems is
required to be maintained in perpetuity and therefore has no finite economic
life. Expenditures on maintaining the operating capability of the network in
accordance with defined
F-121
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
standards of service are capitalized as fixed asset additions and depreciated
each year based on the level of annual expenditures required to maintain the
operating capability of the network based on the independently certified asset
management plan. Under US GAAP, depreciation is required to be charged on all
assets, excluding land, and infrastructure assets are written off in equal
annual installments over 85 years, being the estimated economic life under US
GAAP. The difference between amounts depreciated under UK GAAP for capitalized
maintenance and amounts which would be expensed under US GAAP for maintenance
are not material.
(II) PENSIONS
Under UK GAAP the cost of providing pension benefits under defined benefit
pension schemes is expensed over the average expected service lives of eligible
employees and is aimed to produce an estimate of cost based on long-term
actuarial assumptions. Variations from the regular pension cost arising from,
for example, experience deficiencies or surpluses, are charged or credited to
the profit and loss account over the expected average remaining service lives
of current employees in the schemes.
Under US GAAP the annual pension cost for such schemes comprises the
estimated cost of benefits accruing in the period as determined in accordance
with SFAS 87, which requires readjustment of the significant actuarial
assumptions annually to reflect current market and economic conditions.
(III) GOODWILL, CAPITALISATION AND AMORTISATION
Both UK GAAP and US GAAP require purchase consideration to be allocated to
the net assets acquired at their fair value on the date of acquisition, with
the difference between the consideration paid and the fair value of the
identifiable net assets acquired recognized as goodwill. Under applicable UK
GAAP, goodwill and negative goodwill arising on acquisitions subsequent to
April 1, 1997 are capitalised and amortised over their useful economic lives,
not to exceed 20 years. Goodwill arising on acquisitions prior to that date
were written off against reserves. Under US GAAP, goodwill is capitalised and
amortised over its estimated useful life, not to exceed 40 years. Prior to 1
April 1997, Hyder acquired South Wales Electricity plc, an electricity supply
and distribution business, and the Acer Group Limited, an engineering
consultancy business.
A summary of the movements in the goodwill balance during fiscal year 2000
is as follows:
Goodwill, net of amortization, at December 31, 1999.. 536.7
Amortization of goodwill -- continuing operations.... (20.0)
Amortization of goodwill -- discontinued operations.. (1.8)
Goodwill allocated to sale of discontinued operations (75.4)
Impairment of goodwill(v)............................ (432.0)
------
Goodwill, net of amortization, at December 31, 2000.. 7.5
======
(IV) PROFITS ON DISPOSAL OF BUSINESSES AND INVESTMENTS IN ASSOCIATES
Under UK GAAP, on the subsequent disposal or termination of a previously
acquired business, the profit or loss on disposal is calculated after charging
the amount of any related goodwill previously taken directly to reserves for UK
GAAP. Under US GAAP, unamortized goodwill is taken into account in calculating
profits or losses on disposal.
(V) GOODWILL IMPAIRMENT
Under UK GAAP, goodwill previously written off to reserves is not charged to
profit and loss account if impaired. Under US GAAP, Hyder reviews long-lived
assets for potential impairment whenever events or
F-122
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Recoverability of assets held for use is measured by comparing
the carrying amount of an asset to the undiscounted estimated future cash flows
expected to be generated by the asset. In estimating expected future cash flows
for determining whether an asset is impaired, assets are grouped at the lowest
level for which there are identifiable cash flows that are largely independent
of the cash flows of other groups of assets. If any such assets are considered
to be impaired, the impairment to be recognized is the amount by which the
carrying amount of the assets exceeds its fair value.
Following the electricity price review, effective from 1 April 2000, the
Group reviewed its long lived assets and goodwill for impairment. The
impairment review resulted in identification of an impairment of the goodwill
associated with the acquisition of South Wales Electricity plc.
(VI) DEFERRED TAXATION
Under UK GAAP deferred taxation is calculated, using the liability method,
in respect of timing differences arising from the difference between accounting
and taxable profits. Provision is made for deferred taxation only to the extent
that it is probable that a liability or asset will crystallize in the
foreseeable future.
Under US GAAP deferred tax is provided for on a full liability basis. Under
the full liability method deferred tax assets or liabilities are recognized for
differences between the financial and tax basis of assets and liabilities and
for tax loss carry forwards at the statutory rate at each reporting date. A
valuation allowance is established when it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The deferred
income tax adjustment presented reflects the application of the full liability
method to the UK GAAP financial statements as well as temporary differences
arising from the US GAAP adjustments.
(VII) INVESTMENT PROPERTIES
Under UK GAAP, Hyder values investment properties at fair market value.
Depreciation is not applied, except where properties are held on leasehold with
an unexpired term of 20 years or less. Under US GAAP, investment properties are
valued at cost less accumulated depreciation.
(VIII) CAPITALISED INTEREST
As permitted under UK GAAP, the company expenses interest incurred in
respect of specific or general borrowings to finance the construction of
tangible fixed assets. US GAAP requires that, subject to specific criteria,
such interest should be capitalized and amortized over the useful life of the
related asset.
(IX) ORDINARY DIVIDENDS
Under UK GAAP the proposed and paid ordinary dividends are recognized in the
financial year to which they relate. Under US GAAP such dividends are not
recognized until the period in which they are formally approved.
(X) REDEEMABLE PREFERRED STOCK
Under UK GAAP, redeemable preferred stock is accounted for in equity and the
fixed rate coupon on the preferred stock is treated as dividends.
Under US GAAP all issues of mandatorily redeemable stock are excluded from
the shareholders' equity section of the balance sheet and are presented
separately as long-term debt. Dividends on such stock are treated as interest
and deducted from net income.
F-123
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
(XI) EQUITY MINORITY INTERESTS
Under UK GAAP, minority interests in Hyder group subsidiaries are treated as
an element of equity. Under US GAAP, minority interests are accounted for
outside of equity.
(XII) OWN SHARES--IMPAIRMENT IN VALUE
Under UK GAAP, the company's own shares reacquired are held as fixed asset
investments and are stated at cost less amounts provided to reflect impairment
in value.
Under US GAAP, own shares are classified as treasury stock, which is
recognized as a reduction in shareholders' equity and no impairment is
recognized.
(XIII) BUSINESS DEVELOPMENT COSTS
Under UK GAAP, internal business development costs and contract tendering
costs, in certain circumstances, are capitalized and expensed against future
income streams. Under US GAAP, internal business development costs and contract
tendering costs are expensed as incurred.
(XIV) LISTED INVESTMENTS
Under UK GAAP, listed investments are investments in companies which are
listed on an internationally recognized stock exchange. Under US GAAP, these
investments are classified as available for sale and unrealized holding gains
and losses are excluded from earnings and included as a component of other
comprehensive income within shareholders' funds.
(XV) DEFERRED COMPENSATION
Under US GAAP the difference between market price and grant price of shares
issued under the Employee Sharesave Schemes is recorded in the balance sheet as
deferred compensation and is amortized over the vesting period. Under UK GAAP,
no compensation expense is recognized under the schemes.
(XVI) RESTRUCTURING COSTS
The Company has recorded a provision for planned restructuring costs. Under
US GAAP, certain specific criteria must be met before costs can be included in
a restructuring provision. If these criteria fail to be met, the costs must be
expensed in the financial year in which the costs are incurred. In 1999, under
UK GAAP, Hyder adopted the provisions of FRS 12 which sets forth criteria for
the recognition of restructuring reserves which are substantially consistent
with US GAAP.
(XVII) FINANCIAL INSTRUMENTS
Under UK GAAP, gains and losses on hedges are deferred and recognized in
income when they have crystallised.
Under US GAAP, the applicable accounting practice for financial instruments
depends on management's intention for their disposition and may require
adjustments to their market or fair value. Under US GAAP, the following
conditions must be met for an item to be accounted for as a hedge: (a) the item
to be hedged must expose the company to price or interest rate risk; (b) it
must be probable that the results of the futures contracts will substantially
offset the effects of price or interest rate changes on the hedged item; and
(c) the futures contracts must be designated by management as a hedge of the
item. For futures contracts that are accounted for
F-124
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
as a hedge of items reported at the lower of cost or market, gains and losses
on futures contracts are deferred and recognized in income when costs related
to the hedged item are recognized in income. Derivative financial instruments
held by Hyder which manage the interest rate profile and are not matched by a
primary financial instrument do not qualify for hedge accounting and changes in
their fair value are required to be recorded as a gain or loss in the period.
(XVIII) DISCONTINUED OPERATIONS
During the year ended March 31, 2000, the Group sold its energy supply
business and its environmental laboratories business. Under UK GAAP, both of
these businesses qualify as discontinued operations. Under US GAAP, only the
energy supply business is considered a segment of the Group and qualifies as a
discontinued operation.
(XIX) NET INCOME PER ORDINARY SHARE
Under UK GAAP basic earnings per share is based on the weighted average
number of ordinary shares outstanding during the period after excluding the
weighted average ordinary shares held by the qualifying share option trusts and
the directors' long term incentive plan. Earnings per share is the profit in
pence attributable to each equity share, based on the profit after tax,
minority interests, dividend on preferred stock and exceptional items, divided
by the number of equity shares issued and ranking for dividend in respect of
period. This method is also used for basic earnings per share under US GAAP.
Under UK GAAP, the calculation of fully diluted earnings per ordinary share
is based on the profit after tax, minority interests, dividend on preferred
stock and exceptional items, plus notional interest on outstanding share
options. Under US GAAP, diluted earnings per share must also be disclosed.
Diluted earnings or loss per share is determined by dividing the net earnings
or loss by the sum of (1) the weighted average number of common shares
outstanding and (2) if not anti-dilutive, the effect of outstanding warrants
and stock options determined utilising the treasury stock method. Under this
method, the funds that would be received from the exercise of options are
assumed to be utilised in reacquiring shares. The potential dilution caused by
the exercise of share options therefore represents the difference between the
number of shares that would be issued on the exercise of the option and the
theoretical number of shares that could be reacquired utilising the funds
received.
Earnings per share computed in accordance with US GAAP has been based on the
following number of shares:
FOR THE YEAR ENDED MARCH 31
---------------------------
2000 1999
------ ------
NUMBER NUMBER
(M) (M)
Weighted average number of shares under US GAAP--basic EPS.. 149.3 146.7
Common stock equivalents--dilutive share options............ 0.0 1.0
----- -----
Weighted average number of shares under US GAAP--diluted EPS 149.3 147.7
===== =====
For the year ended March 31, 2000, 0.1 million common stock equivalents were
excluded from the calculation as inclusion of these shares would have been
anti-dilutive.
(XX) CASH FLOW STATEMENTS
The consolidated cash flow statements have been prepared under UK GAAP in
accordance with FRS 1 (revised) and present substantially the same information
as required under SFAS 95. However, there are certain
F-125
HYDER PLC
NOTES TO THE FINANCIAL STATEMENTS--(CONTINUED)
differences between FRS 1 (revised) and SFAS 95 with regard to classification
of items within the cash flow statement.
In accordance with FRS 1 (revised), cash flows are prepared separately for
operating activities, returns on investments and servicing of finance,
taxation, capital expenditure and financial investment, acquisitions and
disposals, equity dividends paid, management of liquid resources and financing.
Under SFAS 95, cash flows are classified under operating activities, investing
activities and financing activities.
Under FRS 1 (revised), cash is defined as cash in hand and deposits
repayable on demand, less overdrafts repayable on demand. Under SFAS 95, cash
and cash equivalents are defined as cash and investments with original
maturities of three months or less. Bank overdrafts have been included within
financing activities under US GAAP.
A summary of the group's cash flows from operating, investing and financing
activities classified in accordance with SFAS 95 is presented below.
2000 1999
------ ------
LM LM
Net cash provided by operating activities........ 257.8 143.8
Net cash used in investing activities............ (257.9) (412.6)
Net cash provided by financing activities........ 22.1 339.1
------ ------
NET INCREASE IN CASH AND CASH EQUIVALENTS........ 22.0 70.3
Effect of exchange rate changes on cash.......... (0.3) 0.2
Cash and cash equivalents at beginning of year... 316.8 246.3
------ ------
CASH AND CASH EQUIVALENTS AT END OF YEAR......... 338.5 316.8
------ ------
CASH AND CASH EQUIVALENTS AT THE END OF YEAR ARE:
Cash at bank and in hand......................... 34.0 21.0
Current asset investments........................ 304.5 295.8
====== ======
F-126
SIUK PLC AND SUBSIDIARIES
MANAGEMENT'S REPORT
2001 ANNUAL REPORT
The management of the Company has prepared, and is responsible for, the
consolidated financial statements and related information included in this
report. These statements were prepared in accordance with accounting principles
generally accepted in the United States appropriate in the circumstances and
necessarily include amounts that are based on the best estimates and judgments
of management. Financial information throughout this annual report is
consistent with the financial statements.
The Company maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that books and records
reflect only authorized transactions of the Company. Limitations exist in any
system of internal controls, however, based on a recognition that the cost of
the system should not exceed its benefits. The Company believes its system of
internal accounting controls maintains an appropriate cost/benefit relationship.
The Company's system of internal accounting controls is evaluated on an
ongoing basis by the Company's internal audit staff. The Company's independent
public accountants also consider certain elements of the internal control
system in order to determine their auditing procedures for the purpose of
expressing an opinion on the financial statements.
Management believes that its policies and procedures provide reasonable
assurance that the Company's operations are conducted according to a high
standard of business ethics.
In management's opinion, the consolidated financial statements present
fairly, in all material respects, the financial position, results of
operations, and cash flows of the Company and its subsidiaries in conformity
with accounting principles generally accepted in the United States.
BARNEY S. RUSH D. CHARL S. OOSTHUIZEN
Chairman and Chief Executive Officer Chief Financial and Accounting Officer
June 22, 2001
F-127
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
SIUK plc:
We have audited the accompanying consolidated balance sheets of SIUK PLC
(the "Company" being a company incorporated in England and Wales) AND
SUBSIDIARIES as of March 31, 2001 and 2000, and the related consolidated
statements of income, changes in stockholder's equity and cash flows for each
of the three years in the period ended March 31, 2001. 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 in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of SIUK plc and
subsidiaries as of March 31, 2001 and 2000 and the consolidated results of its
operations, changes in stockholder's equity and cash flows for each of the
three years in the period ended March 31, 2001, in conformity with accounting
principles generally accepted in the United States.
ARTHUR ANDERSEN
Bristol, England
June 22, 2001
F-128
SIUK PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED MARCH 31, 2001, 2000, AND 1999
(IN MILLIONS)
2001 2000 1999
----------------- ----------- -----------
(NOTE 1)
OPERATING REVENUES............................................................... (Pounds)234 $332 (Pounds)275 (Pounds)261
COST OF SALES.................................................................... 23 33 20 16
----------- ---- ----------- -----------
GROSS MARGIN..................................................................... 211 299 255 245
----------- ---- ----------- -----------
OPERATING EXPENSES:
Maintenance................................................................... 34 48 35 37
Depreciation and amortization................................................. 48 68 56 51
Selling, general and administrative........................................... 8 11 7 35
Write down of meters (Note 3)................................................. -- -- 22 --
Incremental expenses incurred as a direct consequence of the disposal of the
supply business (Note 15)................................................... -- -- 3 --
----------- ---- ----------- -----------
Total operating expenses.................................................. 90 127 123 123
----------- ---- ----------- -----------
OPERATING INCOME FROM CONTINUING OPERATIONS...................................... 121 172 132 122
OTHER INCOME (EXPENSE):
Interest income............................................................... 4 6 2 1
Interest income from affiliated companies..................................... 26 37 20 6
Interest expense.............................................................. (60) (85) (56) (55)
Investment income............................................................. 5 7 7 5
Gain on recognition of deferred contingent consideration (Note 4)............. 16 22 -- --
Gain on sale of assets........................................................ -- -- -- 7
----------- ---- ----------- -----------
Total other expense....................................................... (9) (13) (27) (36)
----------- ---- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES.......................................................................... 112 159 105 86
(PROVISION) BENEFIT FOR INCOME TAXES:
Customary..................................................................... (27) (38) (23) (21)
Effect of change in tax rates (Note 8)........................................ -- -- -- 11
----------- ---- ----------- -----------
NET INCOME FROM CONTINUING OPERATIONS............................................ 85 121 82 76
DISCONTINUED OPERATIONS:
Income from operations of electricity supply business, less applicable
income taxes of (Pounds)- ($-), (Pounds)2 and (Pounds)5..................... -- -- 4 11
Gain on disposal of electricity supply business, less applicable income taxes
of (Pounds)3 ($4) and (Pounds)49 (Note 15).................................. 7 10 125 --
----------- ---- ----------- -----------
NET INCOME....................................................................... (Pounds) 92 $131 (Pounds)211 (Pounds) 87
=========== ==== =========== ===========
The accompanying notes are an integral part of these consolidated statements.
F-129
SIUK PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
FOR THE YEARS ENDED MARCH 31, 2001, 2000, AND 1999
(IN MILLIONS)
ACCUMULATED
NUMBER OF RETAINED OTHER
ORDINARY COMMON EARNINGS/ COMPREHENSIVE COMPREHENSIVE
SHARES STOCK (DEFICIT) LOSS INCOME/(LOSS)
--------- ----------- ------------ ------------- -------------
BALANCE, MARCH 31, 1998............... 500 (Pounds)500 (Pounds)(163) (Pounds) --
Net income......................... -- -- 87 -- (Pounds) 87
------------
Comprehensive income............... -- -- -- -- (Pounds) 87
============
Dividends declared on common stock. -- -- (70) --
Issue of share capital............. 402 402 -- --
--- ----------- ------------ -----------
BALANCE, MARCH 31, 1999............... 902 902 (146) --
Net income......................... -- -- 211 -- 211
------------
Comprehensive income............... -- -- -- -- (Pounds)2 11
============
Dividends declared on common stock. -- -- (188) --
--- ----------- ------------ -----------
BALANCE, MARCH 31, 2000............... 902 902 (123) --
Net income......................... -- -- 92 -- 92
Other comprehensive loss........... -- -- -- (16) (16)
------------
Comprehensive income............... -- -- -- -- (Pounds) 76
============
Dividends declared on common stock. -- -- (27) --
--- ----------- ------------ -----------
BALANCE, MARCH 31, 2001............... 902 (Pounds)902 (Pounds)(58) (Pounds)(16)
=== =========== ============ ===========
The accompanying notes are an integral part of these consolidated statements
F-130
SIUK PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED MARCH 31, 2001, 2000, AND 1999
(IN MILLIONS)
2001 2000
----------------- -----------
(NOTE 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.......................................................................... (Pounds)92 $ 131 (Pounds)211
========== ===== ===========
Adjustments to reconcile net income to net cash provided from operating activities:
Income from operations of discontinued electricity supply business................. -- -- (4)
Gain on disposal of electricity supply business (Note 15).......................... (7) (10) (125)
Depreciation and amortization...................................................... 48 68 56
Write down of meters (Note 3)...................................................... -- -- 22
Gain on recognition of deferred contingent consideration........................... (16) (23) --
Deferred income taxes.............................................................. 10 14 5
Changes in assets and liabilities:
Receivables, net.................................................................. 10 14 (49)
Prepaid pension cost.............................................................. (25) (35) (21)
Accounts payable.................................................................. 2 3 37
Accrued income taxes.............................................................. (1) (1) (4)
Other, net........................................................................ (6) (9) (4)
---------- ----- -----------
Total adjustments............................................................... 15 21 (87)
---------- ----- -----------
Net cash provided from operating activities..................................... 107 152 124
---------- ----- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................................... (73) (104) (67)
Loan to affiliated company......................................................... (85) (121) --
Proceeds from sale of electricity supply business (Note 15)........................ -- -- 160
Proceeds from sales of assets...................................................... -- -- --
Proceeds from sales of investments................................................. 3 4 5
---------- ----- -----------
Net cash (used for) provided from investing activities.......................... (155) (221) 98
---------- ----- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in short term borrowings.................................................... 75 106 (57)
Issue of share capital............................................................. -- -- --
Loan to affiliated company......................................................... -- -- --
Repayment of long term debt........................................................ (1) (1) --
Payment of premium in respect of loans to affiliated company and related hedges.... -- -- --
Payment of dividends............................................................... (27) (38) (188)
---------- ----- -----------
Net cash provided from (used for) financing activities.......................... 47 67 (245)
---------- ----- -----------
CASH PROVIDED BY DISCONTINUED OPERATIONS.............................................. -- -- 20
---------- ----- -----------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................................. (1) (2) (3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR........................................ 2 3 5
---------- ----- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR.............................................. (Pounds)1 $ 1 (Pounds)2
========== ===== ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized)............................................ (Pounds)58 $ 82 (Pounds)56
========== ===== ===========
Income taxes:
Customary....................................................................... 17 24 25
Windfall levy................................................................... -- -- --
---------- ----- -----------
Total cash paid for income taxes............................................. (Pounds)17 $ 24 (Pounds)25
========== ===== ===========
1999
----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.......................................................................... (Pounds)87
==========
Adjustments to reconcile net income to net cash provided from operating activities:
Income from operations of discontinued electricity supply business................. (11)
Gain on disposal of electricity supply business (Note 15).......................... --
Depreciation and amortization...................................................... 47
Write down of meters (Note 3)...................................................... --
Gain on recognition of deferred contingent consideration........................... --
Deferred income taxes.............................................................. 2
Changes in assets and liabilities:
Receivables, net.................................................................. 6
Prepaid pension cost.............................................................. (18)
Accounts payable.................................................................. (14)
Accrued income taxes.............................................................. (34)
Other, net........................................................................ 7
----------
Total adjustments............................................................... (15)
----------
Net cash provided from operating activities..................................... 72
----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................................... (75)
Loan to affiliated company......................................................... --
Proceeds from sale of electricity supply business (Note 15)........................ --
Proceeds from sales of assets...................................................... 10
Proceeds from sales of investments................................................. 2
----------
Net cash (used for) provided from investing activities.......................... (63)
----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in short term borrowings.................................................... 37
Issue of share capital............................................................. 402
Loan to affiliated company......................................................... (351)
Repayment of long term debt........................................................ --
Payment of premium in respect of loans to affiliated company and related hedges.... (42)
Payment of dividends............................................................... (70)
----------
Net cash provided from (used for) financing activities.......................... (24)
----------
CASH PROVIDED BY DISCONTINUED OPERATIONS.............................................. 15
----------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................................. --
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR........................................ 5
----------
CASH AND CASH EQUIVALENTS AT END OF YEAR.............................................. (Pounds)5
==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized)............................................ (Pounds)54
==========
Income taxes:
Customary....................................................................... 2
Windfall levy................................................................... 45
----------
Total cash paid for income taxes............................................. (Pounds)47
==========
The accompanying notes are an integral part of these consolidated statements
F-131
SIUK PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AT MARCH 31, 2001 AND 2000
(IN MILLIONS)
2001 2000
---------------------- -------------
(NOTE 1)
ASSETS
PROPERTY, PLANT, AND EQUIPMENT (NOTE 10)................................................... (Pounds)1,539 $2,184 (Pounds)1,467
Less accumulated provision for depreciation............................................. 247 350 202
------------- ------ -------------
Property, plant, and equipment, net.............................................. 1,292 1,834 1,265
------------- ------ -------------
NONCURRENT ASSETS:
Investments (Note 13)................................................................... 15 21 16
Prepaid pension cost (Note 5)........................................................... 170 241 145
Goodwill, net of accumulated amortization of (Pounds)25 ($35) at March 31, 2001 and
(Pounds)20 at March 31, 2000 (Note 1)................................................. 158 224 163
Loans to affiliated company (Note 12)................................................... 410 582 351
Derivative hedging instruments (Notes 1, 2 and 9)....................................... 56 80 --
Premium in respect of loans to affiliated company and related hedges, net of
accumulated amortization of (Pounds)20 ($28) at March 31, 2001 and (Pounds)12 at
March 31, 2000 (Note 12).............................................................. 22 31 30
------------- ------ -------------
Total noncurrent assets.......................................................... 831 1,179 705
------------- ------ -------------
CURRENT ASSETS:
Cash and cash equivalents............................................................... 1 1 2
Investments (Note 13)................................................................... 10 14 13
Receivables:
Customer accounts, less provision for uncollectables of (Pounds)5 ($7) at March
31, 2001 and (Pounds)2 at March 31, 2000.......................................... 43 61 50
Loan to affiliated company.......................................................... 85 121 --
Other............................................................................... 20 28 14
------------- ------ -------------
Receivables, net................................................................. 148 210 64
Real estate for sale, materials and supplies............................................ 5 7 2
Accrued deferred contingent consideration (Note 4)...................................... 16 23 --
Derivative hedging instruments (Notes 1, 2 and 9).......................................... 25 36 --
Prepaid expenses........................................................................ 13 18 6
------------- ------ -------------
Total current assets............................................................. 218 309 87
------------- ------ -------------
TOTAL ASSETS............................................................................... (Pounds)2,341 $3,322 (Pounds)2,057
============= ====== =============
The accompanying notes are an integral part of these consolidated statements
F-132
SIUK PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS--(CONTINUED)
AT MARCH 31, 2001 AND 2000
(IN MILLIONS)
2001 2000
---------------------- -------------
(NOTE 1)
STOCKHOLDER'S EQUITY AND LIABILITIES
STOCKHOLDER'S EQUITY:
Common stock, (Pounds)1 par value, 902,128,735 shares authorized, issued and
outstanding at March 31, 2001, and March 31, 2000.......................... (Pounds)902 $1,280 (Pounds)902
Accumulated other comprehensive loss (Note 2)................................ (16) (23) --
Retained deficit............................................................. (58) (82) (123)
------------- ------ -------------
Total stockholder's equity............................................... 828 1,175 779
------------- ------ -------------
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SIUK CAPITAL TRUST I HOLDING COMPANY
JUNIOR SUBORDINATED DEBENTURES (NOTE 12)...................................... 58 82 50
COMMITMENTS AND CONTINGENT MATTERS (NOTES 3, 4, 5, 9 AND 12)
NON-CURRENT LIABILITIES:
Long-term debt (Note 12)..................................................... 234 332 301
Deferred income taxes (Note 8)............................................... 419 595 417
Derivative hedging instruments (Notes 1, 2 and 9)............................ 75 106 --
Other........................................................................ 10 14 16
------------- ------ -------------
Total noncurrent liabilities............................................. 738 1,047 734
------------- ------ -------------
CURRENT LIABILITIES:
Current portion of long-term debt (Note 12).................................. 118 168 --
Notes payable to banks (Note 12)............................................. 387 549 311
Notes payable to affiliated company.......................................... 26 37 26
Other notes payable.......................................................... 4 6 5
Accounts payable............................................................. 6 9 4
Taxes accrued................................................................ 46 65 44
Accrued interest............................................................. 9 13 8
Derivative hedging instruments (Notes 1, 2 and 9)............................ 29 41 --
Other........................................................................ 92 130 96
------------- ------ -------------
Total current liabilities................................................ 717 1,018 494
------------- ------ -------------
TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES...................................... (Pounds)2,341 $3,322 (Pounds)2,057
============= ====== =============
The accompanying notes are an integral part of these condolidated statements
F-133
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2001
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
SIUK plc ("the Company"), formerly Southern Investments UK plc, was
incorporated as a public limited company under the laws of England and Wales in
June 1995 as a vehicle for the acquisition of South Western Electricity plc,
one of the 12 Regional Electricity Companies ("RECs") in England and Wales
licensed to distribute, supply and, to a limited extent, generate electricity.
In September 1995, the Company gained effective control of South Western
Electricity plc, and subsequently replaced South Western Electricity plc's
board of directors and certain senior managers with officers and employees of
Southern Company, then the ultimate parent of the Company, and its
subsidiaries. The Company's main investment and only significant asset is the
entire share capital of South Western Electricity plc, which is headquartered
in Bristol, England.
The Company is a wholly owned subsidiary of WPD Holdings Limited
("Holdings"), which in turn has been wholly owned by WPD Holdings UK ("Holdings
UK") since June 1998. From September 1995 to July 1996, Holdings was an
indirect wholly owned subsidiary of Mirant Corporation ("Mirant"), formerly
known as Southern Energy, Inc. In July 1996, Mirant sold a 25% economic
interest in Holdings to a subsidiary of PPL Corporation ("PPL"). In June 1998,
Mirant sold an additional 26% economic interest in Holdings to PPL, and on the
same day both parties agreed to exchange their interests in Holdings for
interests in Holdings UK which carried the same rights. Mirant retained
management control. Effective December 1, 2000, in connection with the
acquisition of Hyder plc, Mirant and PPL modified their ownership of the voting
rights in Holdings UK to 50% each so that both parties share equally
operational and management control. Mirant's and PPL's economic interest in the
Holdings UK group remained unchanged at 49% and 51%, respectively.
In September 1999, South Western Electricity plc completed the sale of its
electricity supply business (known as "SWEB") and certain related activities,
together with the name SWEB, to London Electricity plc for (Pounds)160 million
and the assumption by the purchaser of certain liabilities. South Western
Electricity plc now trades under the name Western Power Distribution ("WPD").
BASIS OF PRESENTATION. The financial statements of the Company are presented
in pounds sterling ((Pounds)) and in conformity with accounting principles
generally accepted in the United States ("US GAAP"). The accompanying financial
statements have not been prepared in accordance with the policies of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" ("SFAS No. 71"). This pronouncement, under which
most US electric utilities report financial statements, applies to entities
which are subject to cost-based rate regulation. By contrast, WPD is not
subject to rate regulation, but, rather is subject to price cap regulation and
therefore the provisions of SFAS No. 71 do not apply. Financial statements
presented in accordance with SFAS No. 71 contain deferred items which have not
yet been included in rates charged to customers in compliance with the
respective regulatory authorities, but which would have been included in the
income statement of enterprises in general under US GAAP. The accompanying
financial statements of the Company do not contain such deferrals.
The consolidated financial statements include the accounts of the Company
and its wholly owned and majority owned subsidiaries and have been prepared
from records maintained by WPD in the United Kingdom. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Investments in companies in which the Company's ownership interests range from
20% to 50% and the Company exercises significant influence over operating and
financial policies are accounted for using the equity method. Other investments
are accounted for using the cost method (Note 13).
F-134
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Solely for the convenience of the reader, certain pounds sterling amounts
included in the financial statements have been translated into US dollars at
the exchange rate of $1.4190 = (Pounds)1.00, the noon buying rate in New York
City for cable transfers in pounds sterling as certified for customs purposes
by the Federal Reserve Bank of New York on March 31, 2001. This presentation
has not been translated in accordance with Statement of Financial Accounting
Standard No. 52, "Foreign Currency Translation".
The following table sets out the exchange rate for previous periods:
FISCAL YEAR PERIOD END AVERAGE (1) HIGH LOW
- ----------- ---------- -------------------- ---- ----
($ PER (POUNDS)1.00)
1997.... 1.64 1.59 1.71 1.49
1998.... 1.68 1.65 1.69 1.61
1999.... 1.61 1.65 1.70 1.60
2000.... 1.59 1.61 1.65 1.58
2001.... 1.42 1.48 1.59 1.42
- --------
(1)The average of the Noon Buying Rates in effect on the last business day of
each month during the relevant period.
ACCOUNTING CHANGE. Effective January 1, 2001, the Company adopted SFAS No.
133, "ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES", which
establishes accounting and reporting standards for derivative instruments and
hedging activities. The statement requires that certain derivative instruments
be recorded in the balance sheet as either assets or liabilities measured at
fair value, and that changes in the fair value be recognized currently in
earnings, unless specific hedge accounting criteria are met. If the derivative
is designated as a fair value hedge, the changes in the fair value of the
derivative and of the hedged item attributable to the hedged risk are
recognized currently in earnings. If the derivative is designated as a cash
flow hedge, the changes in the fair value of the derivative are recorded in
other comprehensive income ("OCI"), and the gains and losses related to these
derivatives are recognized in earnings in the same period as the settlement of
the underlying hedged transaction. If the derivative is designated as a net
investment hedge, the changes in the fair value of the derivative are also
recorded in OCI. Any ineffectiveness relating to these hedges is recognized
currently in earnings. The assets and liabilities related to derivative
instruments for which hedge accounting criteria is met are reflected as
derivative hedging instruments in the accompanying consolidated balance sheet
at March 31, 2001.
The adoption of SFAS No. 133 resulted in a cumulative after-tax reduction to
OCI of (Pounds)13 million, and is attributable to deferred losses on cash flow
hedges. During the twelve month period ending December 31, 2001, the Company
expects to reclassify (Pounds)3 million of the (Pounds)13 million, after-tax
loss from OCI into earnings.
USE OF ESTIMATES. The preparation of financial statements in conformity with
US GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported
amounts of revenue and expense during the reporting period. Actual results
could differ from those estimates.
REVENUE RECOGNITION. WPD records revenue net of value added tax ("VAT") and
accrues revenues for services provided but unbilled at the end of each
reporting period.
CASH AND CASH EQUIVALENTS. The Company considers all short-term investments
with an original maturity of three months or less to be cash equivalents.
F-135
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
LONG-LIVED ASSETS AND INTANGIBLES. The Company records goodwill for the
difference between the excess of the fair value of investments over the
purchase price. Goodwill is amortized on a straight-line basis over a period of
40 years. Goodwill shown in the accompanying consolidated financial statements
relates to the acquisition of South Western Electricity plc. The Company
evaluates long-lived assets, including goodwill and identifiable intangibles,
when events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. The determination of whether an impairment
has occurred is based on an estimate of undiscounted future cash flows
attributable to the assets, as compared to the carrying value of the assets. If
an impairment has occurred, the amount of the impairment recognized is
determined by estimating the fair value of the assets and recording a provision
for loss if the carrying value is greater than the fair value (Note 3).
PROPERTY, PLANT, AND EQUIPMENT. Property, plant, and equipment are recorded
at fair market value as adjusted at the acquisition date in accordance with
Accounting Principles Board Opinion No. 16, "Accounting for Business
Combinations" ("APB No. 16"). Items capitalized subsequent to the acquisition
are recorded at original cost, which includes materials, labor, appropriate
administrative and general costs, and the estimated cost of debt funds used
during construction. The cost of maintenance, repairs, and replacement of minor
items of property is charged to maintenance expense as incurred.
Depreciation of the recorded cost of depreciable property, plant, and
equipment is provided primarily by using composite straight-line rates, which
approximate 3.2% per year (2.5% per year for depreciable utility plant in
service).
Upon the retirement or sale of assets, the cost of such assets and the
related accumulated depreciation are removed from the balance sheet and the
gain or loss, if any, is credited or charged to income.
INFORMATION TECHNOLOGY CONSULTANCY AND DEVELOPMENT COSTS. Significant
information technology ("IT") consultancy and development costs are capitalized
when they become technologically feasible and are amortized over their
estimated useful economic life from the date of first use. Other IT consultancy
and development costs are charged to income in the period in which they are
incurred.
INVESTMENTS. The Company accounts for its current investments in accordance
with SFAS No. 115, "Accounting for Investments for Certain Debt and Equity
Securities". These investments represent investments in debt securities, which
management classifies as available-for-sale securities in accordance with SFAS
No. 115. The Company's long-term investments consist of investments accounted
for using the cost method (Note 13).
The Company recognizes gains on the sale of fixed asset investments once the
receipt of this income is certain. In fiscal year 2001, the Company recognized
a gain in respect of a sale in fiscal year 1997 (Note 4).
INCOME TAXES. SFAS No. 109, "Accounting for Income Taxes", requires the
asset and liability approach for financial accounting and reporting for
deferred income taxes. The Company uses the liability method of accounting for
deferred income taxes and provides deferred income taxes for all significant
income tax temporary differences (Note 8).
FINANCIAL INSTRUMENTS. Derivative financial instruments are used to manage
exposures to fluctuations in interest rates and foreign currency exchange
rates. Derivative gains and losses arising from cash flow hedges that are
included in OCI are reclassified into earnings in the same period as the
underlying transaction.
F-136
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
2. COMPREHENSIVE INCOME (LOSS)
Comprehensive income includes unrealized gains and losses on certain
derivatives which qualify as cash flow hedges. The following table sets forth
the comprehensive income for the year ended March 31, 2001 (in millions):
Net income.................... (Pounds) 92
Other comprehensive loss...... (16)
------------------
Comprehensive income.......... (Pounds)76
==================
Accumulated other comprehensive loss for the year ended March 31, 2001
consisted of the following (in millions):
BALANCE, MARCH 31, 2000.......................................... (Pounds) --
Other comprehensive loss for the period:
Transitional adjustment from adoption of SFAS No. 133......... (13)
Change in fair value of derivative instruments, net of tax.... (4)
Reclassification to earnings, net of tax...................... 1
-----------
Other comprehensive loss......................................... (16)
-----------
BALANCE, MARCH 31, 2001.......................................... (Pounds)(16)
===========
The adoption of SFAS No. 133 resulted in a cumulative after-tax reduction to
OCI of (Pounds)13 million, and is attributable to deferred losses on cash flow
hedges.
The Company estimates that (Pounds)3 million of net derivative after-tax
losses included in OCI as of March 31, 2001 will be reclassified into earnings
or otherwise settled within the next twelve months as certain forecasted
transactions relating to interest payments become realized, and principal
repayments of foreign currency denominated debt are made.
The Company anticipates that SFAS No. 133 will increase the volatility of
other comprehensive income as derivative instruments are valued based on market
indices. Therefore, as market indices change, the change in fair value of the
derivatives will change. For additional information on the adoption of SFAS No.
133, see Notes 1 and 9.
3. WRITE DOWN OF ASSETS
In April 2000, metering services, meter reading and data services for the
domestic and small business market were opened to competition. Metering
services include the provision, installation and maintenance of a meter in a
customer's premise. Meter reading and data services include the collection of
meter reading, aggregation and processing of this data. New license conditions
were introduced obligating distribution companies to offer terms separately for
metering provision, meter operation, data collection and aggregation services
to all suppliers in the domestic market, and to publish a statement of charges
for these activities. An estimate of the undiscounted future cash flows based
on WPD's statement of charges for metering services, was compared to the
carrying value of the assets and it was determined that the assets were
impaired. As a result the Company recorded a write-down of (Pounds)22 million,
in the third quarter of fiscal year 2000, to reflect the amount by which the
carrying value of meters exceeded their fair value. The fair value was
determined by discounting the future cash flows.
F-137
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
4. GAIN ON RECOGNITION OF DEFERRED CONTINGENT CONSIDERATION
During fiscal year 1996, WPD sold its shares of The National Grid Holding
plc ("NGH") into the market, following the listing of the NGH shares on the
London Stock Exchange. Prior to the sale, part of the shareholding was
transferred to three, previously dormant, wholly owned subsidiaries. These
companies sold the shares of NGH in open market transactions during December
1995 and January 1996 generating a taxable gain, resulting in an income tax
liability of (Pounds)24 million. The companies received a capital contribution
from WPD to fund the tax obligation. In October 1996 the companies were sold to
a third party for a nominal price. The sale contract provided for the payment
of contingent consideration based on the third party's ability to utilize its
own existing capital losses to offset the realized gains on the NGH sale. The
agreement provided for (Pounds)16 million to be paid to WPD upon finalization
of the relevant tax returns for the period in question. The last tax return was
agreed by the Inland Revenue in February 2001 and the deferred contingent
consideration received April 6, 2001.
5. RETIREMENT BENEFITS
WPD has two pension plans, a defined contribution plan and a defined benefit
plan. The measurement date for plan assets and obligations is December 31 for
each year.
DEFINED CONTRIBUTION PLAN. The defined contribution plan was established in
fiscal year 1994. The assets of the defined contribution plan are held and
administered by an independent trustee. Contributions to the plan by WPD on
behalf of its employees were (Pounds)0.2 million ($0.3 million) for the fiscal
year 2001, (Pounds)0.2 million for the fiscal year 2000 and (Pounds)0.3 million
for the fiscal year 1999.
DEFINED BENEFIT PLAN. WPD participates in the Electricity Supply Pension
Scheme ("ESPS"), which provides pension and other related defined benefits,
based on final pensionable pay, to substantially all employees throughout the
Electricity Supply Industry in the United Kingdom ("UK"). Contributions to the
plan by WPD on behalf of its employees were (Pounds)0.1 million ($0.1 million)
for the fiscal year 2001, (Pounds)0.2 million for the fiscal year 2000 and
(Pounds)0.3 million for the fiscal year 1999.
PENSIONS CONTINGENCY. The Electricity Supply Pension Scheme ("ESPS")
provides pension and other related defined benefits, based on final pensionable
pay, to substantially all employees throughout the electricity supply industry
in the U.K. The majority of WPD's employees are ESPS members. WPD faces
potential regulatory issues related to the use of pension surplus which was
primarily utilized to offset the cost of providing early pensions to terminated
employees. An independent pension arbitrator has issued a ruling directing that
another industry employer should refund such amounts with interest to the ESPS.
This ruling was appealed to the House of Lords who, in April 2001, upheld the
employer's appeal. It is understood that the complainants are considering
whether to appeal to a European Court. The Company cannot provide assurance
that WPD will not be required to refund to the ESPS any amounts previously used
to fund early retirement costs, which management estimates to be approximately
(Pounds)24 million. Under SFAS 87 "Employers' Accounting for Pensions," the
Company does not anticipate any immediate impact to its net income should such
a payment be required.
F-138
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Changes during the year in the projected benefit obligations and the fair
value of the plan assets were as follows (in millions):
MARCH 31, MARCH 31,
2001 2000
-------------------- ------------
CHANGE IN PROJECTED BENEFIT OBLIGATION
Benefit obligation at beginning of year............... (Pounds)580 $ 823 (Pounds) 639
Service cost.......................................... 6 9 8
Interest cost......................................... 36 51 36
Amendments............................................ -- -- 26
Actuarial loss/(gain)................................. 89 126 (56)
Divestiture........................................... -- -- (30)
Benefits paid......................................... (43) (61) (43)
----------- ------ ------------
Benefit obligations at end of year.................... (Pounds)668 $ 948 (Pounds) 580
----------- ------ ------------
PLAN ASSETS
Fair value of plan assets at beginning of year........ (Pounds)853 $1,211 (Pounds) 786
Actual return on plan assets.......................... (10) (14) 144
Divestiture........................................... -- -- (36)
Employee contributions................................ 1 1 2
Benefits paid......................................... (43) (61) (43)
----------- ------ ------------
Fair value of plan assets at end of year.............. (Pounds)801 $1,137 (Pounds) 853
----------- ------ ------------
RECONCILIATION OF FUNDED STATUS
Funded status of plan................................. (Pounds)133 $ 189 (Pounds) 273
Unrecognized prior service cost....................... 24 34 26
Unrecognized net loss/(gain).......................... 13 18 (154)
----------- ------ ------------
Prepaid pension cost in the Consolidated Balance Sheet (Pounds)170 $ 241 (Pounds) 145
----------- ------ ------------
The components of the plan's net periodic income (excluding the impact of
the Supply sale) were as follows (in millions):
FISCAL FISCAL
FISCAL YEAR YEAR YEAR
2001 2000 1999
------------------- ------------ -----------
Service cost...................... (Pounds) 6 $ 9 (Pounds) 8 (Pounds) 7
Interest cost..................... 36 51 36 39
Expected return on plan assets.... (68) (97) (60) (60)
Amortization of prior service cost 2 3 1 --
Gross benefit credit.............. (24) (34) (15) (14)
Employee contributions............ (1) (1) (2) (4)
Net pension income................ (25) (35) (17) (18)
The assumptions used in the actuarial calculations were as follows:
FISCAL YEAR FISCAL YEAR FISCAL YEAR
2001 2000 1999
----------- ----------- -----------
Discount rate.................... 5.75% 6.50% 5.75%
Expected rate of return on assets 8.75% 8.75% 8.75%
Rate of pay increase............. 4.00% 4.00% 4.00%
F-139
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
6. COMMITMENTS AND CONTINGENT MATTERS
OPERATING LEASES
WPD has commitments under operating leases with various terms and expiration
dates. Expenses associated with these commitments totaled (Pounds)4 million ($6
million) for the fiscal year 2001, (Pounds)6 million for the fiscal year 2000,
and (Pounds)6 million for the fiscal year 1999. At March 31, 2001, estimated
minimum rental commitments for noncancelable operating leases were as follows
(in millions):
FISCAL YEAR
2002................ (Pounds)1
2003................ 1
2004................ 1
2005................ 1
2006................ 1
2007 and thereafter. 3
---------
Total minimum payment.. (Pounds)8
=========
LABOR SUBJECT TO COLLECTIVE BARGAINING AGREEMENTS
Substantially all of WPD's employees are subject to one of two collective
bargaining agreements. Such agreements are ongoing in nature, and WPD's
employee participation level is consistent with that of the electric utility
industry in the UK.
F-140
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
7. SEGMENT AND RELATED INFORMATION
The Company's principal business segment is electricity distribution, which
involves the transfer of electricity from the high voltage transmission system,
and its delivery, across lower voltage distribution systems, to consumers.
Included in "Other" are ancillary business activities that generally support
WPD's distribution business, including electricity generation for standby
purposes, property and telecommunications, as well as corporate items and
assets not allocated to specific segments. Interest expense and taxes are
wholly allocated to "Other" and are disclosed in the Consolidated Income
Statements. With the exception of total assets employed and capital
expenditures, the values below exclude discontinued operations.
BUSINESS SEGMENTS
- - ---------------------------------
FISCAL YEAR DISTRIBUTION OTHER ELIMINATIONS CONSOLIDATED
- ----------- ------------------ ----------------- --------------- ------------------
(IN MILLIONS)
2001
Operating revenues............... (Pounds)217 $ 308 (Pounds)23 $ 33 (Pounds)(6) $(9) (Pounds)234 $ 332
Depreciation and Amortization.... 44 62 4 6 -- -- 48 68
Operating income................. 112 159 9 13 -- -- 121 172
Total assets employed at year-end 1,627 2,309 714 1,013 -- -- 2,341 3,322
Capital expenditures............. 63 90 10 14 -- -- 73 104
2000
Operating revenues............... (Pounds)247 (Pounds)46 (Pounds)(18) (Pounds)275
Depreciation and Amortization.... 52 4 -- 56
Operating income................. 107 25 -- 132
Total assets employed at year-end 1,592 465 -- 2,057
Capital expenditures............. 63 4 -- 67
1999
Operating revenues............... (Pounds)247 (Pounds)49 (Pounds)(35) (Pounds)261
Depreciation and Amortization.... 45 6 -- 51
Operating income................. 111 12 (1) 122
Total assets employed at year-end 1,599 540 -- 2,139
Capital expenditures............. 70 3 -- 73
8. INCOME TAXES
Details of the income tax provision for fiscal years 2001, 2000 and 1999 are
as follows (in millions):
FISCAL YEAR FISCAL YEAR FISCAL YEAR
2001 2000 1999
-------------- ----------- -----------
INCOME TAX PROVISION:
Income tax from continuing operations:
Current provision.................................... (Pounds)17 $24 (Pounds)18 (Pounds)8
Deferred provision................................... 10 14 5 13
---------- --- ---------- ----------
27 38 23 21
Effect of change in tax rates on deferred tax........ -- -- -- (11)
---------- --- ---------- ----------
Total provision from continuing operations....... (Pounds)27 $38 (Pounds)23 (Pounds)10
========== === ========== ==========
Income tax from discontinued operations:
Current provision.................................... (Pounds)-- $-- (Pounds)2 (Pounds)5
Tax on disposal of discontinued operations........... 3 4 49 --
---------- --- ---------- ----------
Total provision from discontinued operations..... (Pounds)3 $ 4 (Pounds)51 (Pounds)5
========== === ========== ==========
F-141
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The UK government's 1998 Finance Act included a reduction in the rate of UK
corporation tax from 31% to 30% effective April 1999. This decrease resulted in
a reduction to WPD's deferred tax liability and a corresponding decrease to
deferred income tax provision of approximately (Pounds)11 million, during
fiscal year 1999.
The tax effects of temporary differences between the carrying amounts of
assets and liabilities in the financial statements and their respective tax
bases which give rise to deferred tax assets and liabilities are as follows (in
millions):
MARCH 31, MARCH 31,
2001 2000
---------------- -----------
DEFERRED TAX LIABILITIES:
Property, plant, and equipment basis differences. (Pounds)338 $480 (Pounds)333
Pensions......................................... 51 72 43
Accruals......................................... -- -- 2
Heldover gain.................................... 40 57 39
Total........................................ 429 609 417
DEFERRED TAX ASSETS:
Accruals, including acquisition related items.... 10 14 --
----------- ---- -----------
Net deferred tax liabilities........................ (Pounds)419 $595 (Pounds)417
=========== ==== ===========
A reconciliation of the Company's UK statutory income tax rate to the
effective customary income tax rate for continuing operations for fiscal years
2001, 2000 and 1999 is as follows:
FISCAL YEAR FISCAL YEAR FISCAL YEAR
2001 2000 1999
----------- ----------- -----------
UK statutory income tax rate.......... 30% 30% 31%
Nondeductible amortization of goodwill 1 1 1
Other permanent differences........... (7) (9) (7)
-- -- --
Effective customary income tax rate... 24% 22% 25%
== == ==
9. FINANCIAL INSTRUMENTS
DERIVATIVE HEDGING INSTRUMENTS
The Company uses derivative instruments to manage exposures arising from
changes in interest rates and foreign currency exchange. The Company's
objectives for holding derivatives are to minimize the risks using the most
effective methods to eliminate or reduce the impacts of these exposures.
Derivative gains and losses arising from cash flow hedges that are included
in OCI are reclassified into earnings in the same period as the settlement of
the underlying transaction. From January 1, 2001, the date of adoption of SFAS
No. 133, to March 31, 2001, (Pounds)1 million of pre-tax derivative losses was
reclassified to other income/expense. The maximum term over which the Company
is hedging exposures to the variability of cash flows is through 2012.
INTEREST RATE HEDGING
The Company's policy is to manage interest expense using a combination of
fixed- and variable-rate debt. To manage this mix in a cost-efficient manner,
the Company enters into interest rate swaps in which it agrees to
F-142
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
exchange, at specified intervals, the difference between fixed and variable
interest amounts calculated by reference to agreed-upon notional principal
amounts. These swaps are designated to hedge underlying debt obligations. For
qualifying hedges, the changes in the fair value of gains and losses of the
swaps are deferred in OCI, net of tax, and the interest rate differential is
reclassified from OCI to interest expense as an adjustment over the life of the
swaps.
FOREIGN CURRENCY HEDGING
The Company utilizes cross currency swaps and other derivatives that offset
the effect of exchange rate fluctuations on US dollar denominated instruments
and fixes the interest rate exposure. These derivatives qualify as cash flow
hedges, and gains and losses on the derivatives are deferred in OCI, net of
tax, until the forecasted transaction affects earnings. The reclassification is
then made from OCI to earnings to the same expense or income category as the
hedged transaction.
CREDIT RISK
The Company is exposed to losses in the event of nonperformance by
counterparties to its derivative financial instruments. The Company has
established controls to determine and monitor the creditworthiness of
counterparties in order to mitigate the Company's exposure to counterparty
credit risk. The Company is unaware of any counterparties that will fail to
meet their obligations.
FAIR VALUES
SFAS No. 107, "Disclosures About Fair Value of Financial Instruments,"
requires the disclosure of the fair value of all financial instruments.
The carrying or notional amounts and fair values of the Company's financial
instruments at March 31, 2001 and 2000 were as follows (in millions):
MARCH 31, 2001 MARCH 31, 2000
----------------------- -----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
----------- ----------- ----------- -----------
Liabilities
Long-term debt, including current portion. (Pounds)352 (Pounds)350 (Pounds)301 (Pounds)298
Preferred securities...................... (Pounds)58 (Pounds)45 (Pounds)50 (Pounds)46
Receivables
Loans to affiliated company............... (Pounds)410 (Pounds)395 (Pounds)351 (Pounds)344
The fair values for long-term debt and preferred securities were based on
the closing market price.
Prior to the adoption of SFAS No. 133, the carrying value of hedged foreign
currency denominated instrument was translated using the exchange rate of the
related cross currency derivative. The adoption of SFAS No. 133 requires
foreign currency denominated instruments be carried at the current period end
spot rate, and derivatives to be recorded in the balance sheet at fair value.
Reference is made to Note 1 for further information on the adoption of SFAS No.
133.
The change in the carrying value of long-term liabilities and receivables
above is due to the movement between the derivative exchange rate used at March
31, 2000 and the spot rate used at March 31, 2001.
F-143
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
10. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following (in millions):
MARCH 31, 2001 MARCH 31, 2000
--------------------- --------------
Distribution network............... (Pounds)1,279 $1,815 (Pounds)1,244
Non-network land and buildings..... 30 43 34
Other.............................. 49 70 40
Consumer contributions............. (66) (94) (53)
------------- ------ -------------
Property, plant, and equipment, net (Pounds)1,292 $1,834 (Pounds)1,265
============= ====== =============
11. CAPITAL BUDGET
The Company's capital expenditure for the fiscal year 2001 was (Pounds)73
million ($104 million); for the fiscal years 2002 and 2003 capital expenditures
are estimated to be (Pounds)65 million and (Pounds)62 million respectively. The
capital budget is subject to periodic review and revision, and actual capital
cost incurred may vary from the above statement because of numerous factors.
The factors include: changes in business conditions; revised load growth
projections; change in regulatory requirements; and increasing costs of labor,
equipment, and materials.
12. DEBT
The Company has $500 million Senior Notes in the US, of which some $168
million of the Senior Notes are due for redemption in November 2001 and $332
million in 2006; the Senior Notes are at rates of 6.375% and 6.8% respectively.
The Company entered into currency swap transactions that effectively convert
the US dollar obligations of the Senior Notes into pounds sterling obligations,
with a nominal value of (Pounds)300 million.
SIUK Capital Trust I (the "Trust"), formerly Southern Investments UK Capital
Trust I, issued $82 million of its 8.23% preferred securities and invested the
proceeds thereof in 8.23% subordinated debentures issued by the Company, which
are scheduled to mature on February 1, 2027. The Company guarantees the Trust's
obligations under the preferred securities. The Company has also entered into
foreign currency swap contracts to hedge the currency risk associated with the
interest and principal on the preferred securities, by swapping the US dollar
liabilities back to pounds sterling for the period to February 2007. The
nominal value of the swapped liabilities is (Pounds)50 million. The Company
owns all of the common securities of the Trust, all of the assets of which are
the aforementioned subordinated debentures of the Company in the aggregate
principal amount of $84.5 million.
The Company considers that the mechanisms and obligations relating to the
preferred securities, taken together, constitute a full and unconditional
guarantee by the Company of the Trust's payment obligations with respect to the
preferred securities.
In December 1998 a more efficient capital structure for Holdings UK and the
Company was put in place. At that time, Holdings UK became a co-obligor of the
Company's existing long-term debt and subordinated debentures. Sums totaling
(Pounds)402 million were contributed to the Company for newly issued shares and
the Company made three US dollar loans, totaling $584 million ((Pounds)351
million) to Holdings UK on the same terms as the existing long-term debt and
subordinated debentures. At March 31, 2001, the carrying value of these loans
was (Pounds)410 million (Note 9). In consideration of entering into these loans
and their related currency and interest rate swaps, the Company made premium
payments (independently calculated as a fair arms-length value between
unconnected parties) of $84 million ((Pounds)51 million) to Holdings UK. Of the
premium payments, (Pounds)42 million is being amortized over the life of the
respective loans and swaps, and (Pounds)9 million represented accrued interest.
F-144
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
As of March 31, 2001, sources of liquidity included a $520 million US
commercial paper program, $503 million of which is supported by a swingline and
revolving credit facility provided by a syndicate of banks. In addition, the
Company had (Pounds)100 million committed and (Pounds)110 million uncommitted
lines of credit with banks. The Company's existing facilities and cash position
are expected to provide sufficient liquidity for working capital and capital
expenditures through fiscal year 2002. As of March 31, 2001 the Company and WPD
had drawn $445 million under the swingline and revolving credit facility and
(Pounds)80 million under committed lines of credit with banks. Additionally,
the Company held (Pounds)1 million in unrestricted cash.
Excluding swap agreements between the Company and Holdings UK, at March 31,
2001, the Company and WPD have sterling interest rate swaps expiring between
2001 and 2012 with notional amounts totaling (Pounds)600 million, and cross
currency swaps expiring between 2001 and 2007 with notional amounts totaling
(Pounds)350 million
13. INVESTMENTS
The Company's long-term investments accounted for under the cost method
consist of its 7.69% ownership of Teesside Power Limited, the fair value of
which is not readily determinable. The Company's (Pounds)10 million of
short-term investments are classified as available-for-sale under SFAS No. 115,
the fair value of which approximated cost at March 31, 2001.
14. COMMON STOCKHOLDER'S EQUITY
The Company holds the entire share capital of WPD. The Company is primarily
dependent upon dividends from WPD for its cash flow. WPD can make distribution
of dividends to the Company under English law to the extent that it has
distributable reserves, subject to the retention of sufficient financial
resources to conduct its distribution business as required by its regulatory
license. The Company believes that currently sufficient distributable reserves
will continue to exist at WPD to allow for reasonable and necessary dividends
from WPD, through operations, to be distributed to the Company. In the U.K.,
the Accounting Standards Board has recently issued a new accounting standard,
Financial Reporting Standard ("FRS") 19 "Deferred Tax" ("FRS 19"), relating to
the accounting treatment of deferred income tax. FRS 19, which replaces an
earlier standard (SSAP 15), is mandatory for accounting periods ending on or
after January 23, 2002 (though earlier adoption is encouraged), and will
require full provision to be made for deferred tax assets and liabilities (SSAP
15 only required a partial provision basis); discounting of deferred tax
liabilities will be permitted but is not mandatory. WPD will take advantage of
the discounting option, but adoption of FRS 19 will significantly reduce WPD's
distributable reserves. The directors of Distribution companies must also
certify to the Regulator that it is reasonably foreseeable that the declaration
of a dividend will not breach any license conditions. WPD has no reason to
believe that a breach of its license would occur from declaring a reasonable
dividend.
15. BUSINESS DEVELOPMENTS
In September 1999, WPD completed the sale of its electricity supply business
(known as 'SWEB') and certain related activities, together with the name
'SWEB', to London Electricity plc for (Pounds)160 million and the assumption by
the purchaser of certain liabilities. The Company recorded an after tax gain on
the sale of (Pounds)125 million in fiscal year 2000. In fiscal year 2001,
issues relating to working capital and pension spin off value were resolved and
a further (Pounds)7 million after tax gain was recorded.
In October 2000, an affiliate acquired Hyder plc which owned numerous
businesses including that which owned and operated the electricity network in
South Wales. In March 2001, this business was transferred to the ownership of
the Company's ultimate parent, WPD Holdings UK. The management of the Company
and of WPD
F-145
SIUK PLC AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
has become involved in the electricity business in South Wales, and this
business will share a number of WPD key systems.
16. SUBSEQUENT EVENTS
On April 2, 2001, Southern Company distributed their remaining 80% interest
in Mirant Corporation, an indirect parent of the Company, to Southern Company's
stockholders.
F-146
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Managers and
Sole Member of PPL Energy Supply, LLC:
Our audits of the consolidated financial statements referred to in our
report dated June 15, 2001appearing in the Registration Statement on Form S-4
of PPL Energy Supply, LLC also included an audit of the financial statement
schedule on page F-148 of such Registration Statement. In our opinion, this
financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.
/S/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Philadelphia, PA
June 15, 2001
F-147
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- --------- -------------- ---------- ---------
ADDITIONS
BALANCE ---------
AT CHARGED BALANCE
BEGINNING TO AT END OF
DESCRIPTION OF PERIOD INCOME OTHER DEDUCTIONS PERIOD
----------- --------- --------- ----- ---------- ---------
(Millions of Dollars)
PPL ENERGY SUPPLY
YEAR ENDED DECEMBER 31, 2000
Reserves deducted from assets in the Balance Sheet
Uncollectible accounts......................... $3 $24 $26 (1) $1 $52
Obsolete inventory--Materials and supplies..... 4 4
YEAR ENDED DECEMBER 31, 1999
Reserves deducted from assets in the Balance Sheet
Uncollectible accounts......................... 3 (2) 3
YEAR ENDED DECEMBER 31, 1998
Reserves deducted from assets in the Balance Sheet
None...........................................
- --------
(1) Includes the allowance for doubtful accounts recorded upon the
acquisition of CEMAR by PPL Global.
(2) Includes the allowance for doubtful accounts associated with the
consolidation of Emel and EC by PPL Global.
F-148
ANNEX A
SUMMARY INDEPENDENT
TECHNICAL REVIEW
Summary of the
Independent Technical
Review
PPL Energy Supply, LLC
August 15, 2001
[LOGO] Stone & Webster Consultants
A Shaw Group Company
A-1
(This Page Intentionally Left Blank)
A-2
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
LEGAL NOTICE
This document was prepared by Stone & Webster Consultants, a Division of Stone &
Webster, Inc., hereafter referred to as Stone & Webster, expressly for PPL
Corporation, its Underwriters/Lenders/Arrangers, and the Rating Agencies.
Neither Stone & Webster, nor PPL, nor its subsidiaries, nor its
Underwriters/Lenders/Arrangers, nor the Rating Agencies, nor any person acting
on their behalf: (a) makes any warranty, express or implied, with respect to the
use of any information or methods disclosed in this report; or (b) assumes any
liability with respect to the use of any information or methods disclosed in
this report. Stone & Webster's review of information and financial modeling
relating to PPL Energy Supply, LLC in no way serves to transfer to Stone &
Webster responsibility for the correctness and/or accuracy of such information
or modeling results.
Information furnished hereunder that is provided to third parties will be
provided in its entirety unless otherwise approved by Stone & Webster.
Any recipient of this document, by their acceptance or use of this document,
releases Stone & Webster, its affiliates, and PPL and its affiliates, and the
Underwriters/Lenders/Arrangers, from any liability for direct, indirect,
consequential or special loss or damage whether arising in contract, tort or
otherwise, and irrespective of fault, negligence, and strict liability."
ELECTRONIC MAIL NOTICE
Electronic mail copies of this report are not official unless authenticated and
signed by Stone & Webster and are not to be modified in any manner without Stone
& Webster's expressed written consent.
A-3
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1. EXECUTIVE SUMMARY
1.1 Introduction
Stone & Webster has prepared this Independent Technical Review ("Report") of PPL
Energy Supply, LLC for PPL Corporation and its Underwriters/Lenders/Arrangers.
PPL Energy Supply, LLC is an unregulated indirect wholly-owned subsidiary of PPL
Corporation. PPL Energy Supply was formed as a subsidiary of PPL Energy Funding,
to engage through subsidiaries in competitive energy businesses, and will serve
as the parent of PPL Generation, PPL EnergyPlus, PPL Global and other
subsidiaries. PPL Generation owns and operates domestic electric generating
facilities. Wholesale and retail energy marketing is performed by PPL
EnergyPlus. PPL Global is responsible for the acquisition and development of
both domestic and international energy projects, and the ownership and operation
of international energy projects. Also referenced in this Report is PPL Electric
Utilities Corporation (PPL Electric Utilities), which is PPL's regulated
electric transmission and distribution company. Both PPL Energy Supply, LLC and
PPL Corporation are generally referred to in this Report as PPL.
This Report contains a description of the major electric generating facilities
and three of the international electric distribution companies owned by PPL and
the findings on an independent technical assessment of these assets and
companies. The major assets and companies within PPL Energy Supply, LLC include
the following:
o Domestic electric generating assets located in Pennsylvania,
Montana, and Maine
o Domestic electric generating assets under development in Arizona,
Connecticut, Pennsylvania, Washington, and New York
o International transmission and distribution companies in South and
Central America and Great Britain
o International electric generating assets
The domestic electric generating assets include fossil fuel-fired, nuclear, and
hydroelectric units. The fossil-fired units are predominantly coal-fired and
include both wholly owned and jointly owned generating stations. The large
wholly owned coal-fired stations include Brunner Island and Montour Stations in
Pennsylvania. The jointly owned coal-fired stations include Conemaugh and
Keystone Stations in Pennsylvania and Colstrip Station in Montana. In addition
to the large coal-fired stations, PPL owns a 90% share in the two unit
Susquehanna Nuclear Generating Station in Pennsylvania and hydroelectric
facilities in Pennsylvania, Montana, and Maine. The electric generating assets
in Montana and Maine were acquired by PPL Global from electric utilities
(Montana Power and Bangor Hydro) that were divesting their electric generating
assets as part of the on-going restructuring of the electric industry. The
electric generating assets in Pennsylvania are the facilities that were
transferred from the regulated to the unregulated side of PPL as part of PPL's
corporate realignment on July 1, 2000.
PPL's new electric generating facility development efforts are currently focused
on gas-fired simple cycle or combined cycle combustion turbine facilities. The
most advanced is the combined cycle Griffith Energy Project in Arizona which
recently entered commercial operation. The Griffith Energy Project is jointly
owned with Duke Energy. PPL is also developing two other combined cycle projects
- -- the Lower Mount Bethel Project and the Starbuck Project. The Lower Mount
Bethel Project is located in eastern Pennsylvania and is expected to go into
A-4
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
construction shortly. The Starbuck Project is on Washington State and is not as
far along in development.
PPL is also pursuing a number of simple cycle facilities that are intended to
provide power during peak periods. PPL is focusing its simple cycle facility
development efforts around the GE LM6000 aeroderivative combustion turbine. It
has developed a standard configuration and executed bulk equipment purchases to
support the installation of up to 33 generation blocks (two combustion turbines
per block), each with the capacity to generate 90 MW. The first simple cycle
project is in Wallingford, Connecticut, and is currently in start-up. PPL is
pursuing a number of additional simple cycle facilities in Pennsylvania, New
York, Arizona, and Illinois. PPL Global is the developer of these new simple
cycle and combined cycle projects.
PPL Global owns several electric distribution companies in Latin America and
Europe. The Latin American electric distribution companies include the
following:
o Empresas Emel S.A. (Emel) -- PPL Global owns 95% of Emel. Emel is a
holding company for five Chilean electric distribution companies
that serve 450,000 customers in northern and central Chile.
o Empresa de Luz y Fuerza Electrica Cochamamba S.A (Elfec) -- PPL
Global owns 92% of Elfec. Elfec serves 209,000 customers in the
Cochabamba area in Bolivia.
o Distribuidora de Electridad del Sur (DelSur) -- PPL Global owns
80.5% of DelSur. DelSur serves 216,000 customers in central and
southern El Salvador.
o Companhia Energetica do Maranhao (CEMAR) -- PPL Global owns 84.7% of
CEMAR. CEMAR serves 977,000 customers in northeastern Brazil.
PPL Global also a 17% interest in the Latin America Energy and Electricity Fund
(FondElec) which has energy holdings in Argentina, Bolivia, and Brazil. FondElec
has ownership stakes in the following: Transredes S.A., a natural gas and oil
pipeline operator in Bolivia; EDEER S.A., an electric distribution company
serving northeastern Argentina; and Cataguazes Leopoldina, an electric
distribution company serving eastern Brazil.
PPL Global owns 51% of Western Power Distribution, a British regional utility
serving southwest England. The balance of WPD is owned by Southern Energy, Inc.
which also manages WPD. Recently, WPD acquired Hyder, an integrated utility in
Wales. The non-electric distribution elements of Hyder are being sold and the
electric distribution company, SWALEC, is being integrated into WPD.
In addition to international electric distribution companies, PPL Global also
owns several international generation assets. These assets including Empresa
Electrica Valle Hermosa S.A. (EVH) in Bolivia, Aguaytia Integrated Energy
Project in Peru, and several hydroelectric plants in Spain and Portugal. EVH
is an electric generation company that operates two natural gas-fired power
plants and three hydroelectric units. The total generating capacity of EVH is
194 MW. PPL Global owns 14.7% of EVH. The Aguaytia Integrated Energy Project
consists of a natural gas field and two simple cycle combustion turbines. The
total output of the project is 155 MW which is carried by a dedicated 250-mile
220 kV transmission line from central Peru over the Andes Mountains to the coast
north of Lima. PPL Global owns 11.4% of the Aguaytia Integrated Energy Project.
The hydroelectric plants in Spain and Portugal have an installed capacity of 66
MW. PPL Global has a 49% ownership stake in these generation assets.
A-5
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.2 Scope Of Work
Stone and Webster was retained by PPL and the Initial Bond Purchaser to prepare
an Independent Technical Review for the bond financing being pursued by PPL. The
Independent Technical Review includes a condition assessment, remaining asset
life evaluation, performance and operation and maintenance review, and an
environmental assessment of the Assets. No environmental site assessments had
been prepared by PPL for the facilities reviewed by Stone & Webster.
Consequently, Stone & Webster did not review environmental site assessments for
the Assets to assess any site contamination risk. Furthermore, a PPL subsidiary
owns and operates an oil and gas pipeline that supplies the Martinis Creek
Station with fuel. The review of the pipeline and the oil storage facilities
located at the Martins Creek Station were not included in our scope of work.
Stone & Webster reviewed all the major assets of PPL Energy Supply, LLC except
for the assets purchased from WPD. The Montana Power assets were recently
evaluated by another independent engineer as part of the financing associated
with the acquisition of these assets. Stone & Webster updated that review to
incorporate changes that have occurred in the last 2 years. The update involved
limited site visits to the Montana hydroelectric and coal-fired units. A review
of WPD was planned but not performed due to scheduling conflicts associated with
the integration of WPD and SWALEC. A limited review was performed of certain
secondary assets, such as the assets purchased from Bangor Hydro and DelSur. The
review of the development facilities was also limited based on the state of
development of these projects. Griffith Energy recently entered commercial
operation. Construction activities in Wallingford are complete and the plant is
in start-up. The planned peaking facilities are in varying stages of development
with limited documentation available for our review.
Stone & Webster's primary focus was technical review of the generating
facilities located in Pennsylvania and two more significant electric
distribution companies in Latin America (Emel and CEMAR).
As part of the Independent Technical Review, Stone & Webster developed a
financial model for PPL Energy Supply, LLC, which combined the market forecasts
prepared by the Market Consultant with the contracted revenue forecasts,
operation and maintenance expenses, and capital expenditure forecasts. The pro
forma financial projections prepared using the financial model show cash flows
available to support the repayment of the debt and debt service coverage ratios
for a base case and several sensitivity cases from 2001 through 2020.
The Report includes Stone & Webster's independent technical assessment of the
Assets, based on, among other things, the review of the available technical
data, historic performance and cost data, and visits to significant and/or
representative facilities. The Report presents our findings and conclusions
regarding the following:
o the condition and expected remaining life of the Assets
o the projected capital costs, operating and maintenance expenses, and
environmental issues relating to the future operation and
maintenance of the facilities; and
o the pro forma financial projections of cash flows under base case
and sensitivity assumptions (collectively the "Financial
Projections").
A-6
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.3 Description And Condition Of Electric Generating Assets
Stone & Webster prepared detailed technical descriptions of the major electric
generating assets, some of which is summarized in this section. Using the
technical descriptions, inspection and overhaul reports on the assets, notes
from interviews with plant operating and maintenance staff and our knowledge of
the electric generation industry and comparable electric generating facilities,
we prepared a condition assessment of the major electric generating assets. The
condition assessment was used in conjunction with the operating and maintenance
plans to establish the expected life of the assets and certain performance
parameters used by the Market Consultant to prepare the market forecasts for the
assets.
1.3.1 Technical Description of Electric Generating Assets
The assets that support the operation of PPL Energy Supply include a mixture of
domestic and international assets. The domestic assets include a portfolio of
generating facilities located in Pennsylvania, Montana and Maine. The
international assets are a mix of generating assets and distribution companies,
with the bulk of the international assets being distribution companies.
For purposes of this Report, the domestic electric generating facilities have
been organized into several groupings with certain common characteristics. These
groupings include four bundles of domestic generating assets and the
international distribution companies. The four bundles of domestic generating
assets are as follows:
o Existing Fossil Fuel-Fired Generating Stations
o Fossil Fuel-Fired Generating Stations under Development
o Nuclear Generating Stations
o Hydroelectric Generating Stations
The total existing generating capability of the domestic generation portfolio is
9,265 MW. In 2005 when the announced new development projects and the
Susquehanna uprate projects are completed, the total generating capability will
be 10,124 MW.
1.3.1.1 Existing Fossil Fuel-Fired Generating Assets
The existing fossil fuel-fired generating assets consist primarily of facilities
in Pennsylvania, with major stations in Montana, and a limited set of assets in
Maine. The existing Pennsylvania fossil fuel-fired generating assets include the
following:
o Brunner Island Station
o Martins Creek Station
o Montour Station
o Conemaugh Station
o Keystone Station
o Fleet of Combustion Turbines (Allentown, Fishbach, Harrisburg,
Harwood, Jenkins, Lock Haven, Martins Creek CTs, West Shore, and
Williamsport)
A-7
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The existing fossil fuel-fired generating assets in Montana and Maine include
Colstrip and Corette Stations in Montana and Wyman Unit 4 in Maine. Key
characteristics of these assets are shown in Table 1-1.
As can be seen in Table 1-1, not all of the assets are wholly owned by PPL. The
wholly owned assets are Brunner Island, Corette, Martins Creek, Montour and the
fleet of combustion turbines. Conemaugh and Keystone are owned-jointly with
several other generating companies with PPL having a 16.25% share of Conemaugh
and a 12.34% share of Keystone. PPL jointly owns 50% of Colstrip Units 1 and 2
with Puget Sound Energy, Inc. PPL also owns 30% of Colstrip Unit 3. PPL owns an
8.33% ownership interest in Wyman Station Unit 4.
Table 1-1
PPL Existing Fossil-Fuel Fired Assets
- -------------------------------------------------------------------------------------------------------------------------------
Station Name State Unit In Type Rated Capacity Primary Fuel Operating
Service (MW) Mode
Date -------------------
Total PPL
Share
- ------------------------------------------------------------------------------------------------------------------------------
Allentown PA 1 - 4 1967 Combustion Turbine 56 56 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Brunner Island PA 1 1961 Steam Electric 321 321 Coal Baseload
-------------------------------------------------------------------------------------------------
2 1965 Steam Electric 378 378 Coal Baseload
-------------------------------------------------------------------------------------------------
3 1969 Steam Electric 735 735 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
Colstrip MT 1 1975 Steam Electric 307 154 Coal Baseload
-------------------------------------------------------------------------------------------------
2 1976 Steam Electric 307 154 Coal Baseload
-------------------------------------------------------------------------------------------------
3 1984 Steam Electric 740 222 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
Conemaugh PA 1 1970 Steam Electric 850 138 Coal Baseload
-------------------------------------------------------------------------------------------------
2 1970 Steam Electric 850 138 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
Corette MT 1 1968 Steam Electric 154 154 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
Fishbach PA 1 - 2 1969 Combustion Turbine 28 28 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Harrisburg PA 1 - 4 1967 Combustion Turbine 56 56 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Harwood PA 1 - 2 1967 Combustion Turbine 28 28 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Jenkins PA 1 - 2 1969 Combustion Turbine 28 28 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Keystone PA 1 1967 Steam Electric 850 105 Coal Baseload
-------------------------------------------------------------------------------------------------
2 1968 Steam Electric 850 105 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
Lock Haven PA 1 1969 Combustion Turbine 14 14 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Martins Creek PA 1 1954 Steam Electric 140 140 Coal Intermediate
-------------------------------------------------------------------------------------------------
2 1956 Steam Electric 140 140 Coal Intermediate
-------------------------------------------------------------------------------------------------
3 1975 Steam Electric 820 820 Residual Oil/Gas Peaking
-------------------------------------------------------------------------------------------------
4 1977 Steam Electric 820 820 Residual Oil/Gas Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Martins Creek CT PA 1 - 4 1971 Combustion Turbine 72 72 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Montour PA 1 1973 Steam Electric 745 745 Coal Baseload
-------------------------------------------------------------------------------------------------
2 1973 Steam Electric 765 765 Coal Baseload
- ------------------------------------------------------------------------------------------------------------------------------
West Shore PA 1 - 2 1969 Combustion Turbine 28 28 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Williamsport PA 1 - 2 1969 Combustion Turbine 28 28 Distillate Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
Wyman ME 4 1978 Steam Electric 615 51 Residual Oil Peaking
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL 10,725 6,439
- ------------------------------------------------------------------------------------------------------------------------------
PPL's existing fossil fuel-fired generation assets are predominantly coal-fired
and provide baseload generation. Of the total fossil-fuel-fired generation
capacity owned by PPL, 70% is
A-8
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
coal-fired and 65% is baseloaded. From a generation standpoint, essentially all
of PPL's fossil fuel-fired generation comes from its coal-fired power plants.
PPL's coal-fired generating assets are a mix of large (greater than 500 MW),
medium (250 to 500 MW). and small (under 250 MW) units. PPL owns or has
ownership interests in eight coal-fired units with capacities between 740 MW and
850 MW. The large coal-fired units include Brunner Island Unit 3, Colstrip Unit
3, Conemaugh Unit 1 and 2, Keystone Units 1 and 2, and Montour Units 1 and 2.
The medium-sized coal fired units include Brunner Island Units 1 and 2 and
Colstrip Units 1 and 2. The small coal-fired units are Corette Unit 1 and
Martins Creek Units 1 and 2.
Aside from the coal-fired units, the other significant generating assets are the
two oil and gas fired units at Martins Creek (Units 3 and 4). These units were
originally oil-fired only but were recently converted by PPL to have dual-fuel
capability. The units have historically been used as large seasonal peaking
units and provide a large block of capacity available to supply power during
peak demand periods.
Stone & Webster performed a detailed review of PPL's fossil fuel-fired steam
electric units in Pennsylvania in the summer/fall of 2000, which included site
visits to the fossil-fired steam electric generating stations. This review has
recently been updated to reflect changes that have occurred since that time. The
fossil fuel-fired steam electric units in Montana (Colstrip and Corette
Stations) were reviewed by another independent engineer as part of the PPL
Montana financing. Certain information for Colstrip and Corette Stations was
obtained from the PPL Montana Bond Offering Memorandum. Stone & Webster has
recently performed an update to reflect changes at the Montana fossil-fired
since the PPL Montana financing. Stone & Webster did not review Wyman Unit 4 in
Maine. Wyman Station Unit 4 was not reviewed as PPL's ownership interest is
small (8.33%). The limited descriptive data and information used on Wyman Unit 4
was obtained from PPL and other sources.
PPL operates 23 peaking combustion turbines, all of which were commissioned from
1967 to 1971. Many of the units are located at the extremities of the PPL
transmission system and were installed to provided voltage support for the
electric grid. For most of their life, the combustion turbines have been
operated in peak service, providing power at times of high demand or replacing
capacity lost due to forced outages.
The existing combustion turbine fleet is comprised of three different type of
units -- GE Frame 5 Model LA, GE Frame 5 Model N, and Pratt & Whitney (P&W)
FT4A8LF. The fleet is summarized in 2-1. With the exception of Lockhaven, which
is a single unit, the other multiple unit sites were developed as power blocks
with some common equipment and shared auxiliaries. The units are all fueled with
No. 2 fuel oil stored in an onsite tank. Stone & Webster visited three of the
combustion turbine sites (Fishbach, Allentown and Martins Creek) as these sites
had one of the three types of combustion turbines that PPL owns. The sites were
clean and the appearance was good. PPL has replaced the exhaust stacks on every
unit.
1.3.1.2 Projects Under Development
New electric generating projects currently being developed by PPL include both
simple cycle and combined cycle projects. The simple cycle projects are all
based around GE LM6000 combustion turbine generators. PPL has standardized the
configuration of the its simple cycle projects and has executed bulk purchase
agreements with the suppliers of the major equipment including the combustion
turbine generator, main transformer, and selective catalytic reduction
equipment. PPL has three combined cycle facilities in various states of
development. The Griffith Energy facility in Arizona has recently entered
commercial operation. This facility is co-owned with Duke Energy, who is a 50%
owner along with PPL. The Lower Mount Bethel Station, which is
A-9
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
located adjacent to PPL's Martins Creek Station in Pennsylvania, is in advanced
development and is expected to enter construction in late 2001.
PPL is developing peaking facilities based on GE LM6000 Enhanced SPRINT
combustion turbines operated in simple cycle mode. The most advanced of the
projects is in Wallingford, Connecticut. The Wallingford project is currently in
start-up. Additional projects include three facilities in Pennsylvania (West
Earl, Eden, and Upper Hanover). PPL has announced additional projects in
University Park, Illinois, Pinal County, Arizona, and Kings Park, New York. PPL
is currently focused on pushing the development of the larger projects that
consist of 10 to 12 combustion turbine generators such as Pinal County
(Sundance) and University Park. Both of these projects are expected to be in
commercial service in the summer of 2002.
Key characteristics of the new simple cycle and combined cycle projects that
were included in the Financial Projections are shown in Table 1-2.
Table 1-2
Fossil-Fuel Fired Projects under Development
- ---------------------------------------------------------------------------------------------------------------------------
Station Name State Units In Service Type Rated Capacity Primary Fuel Operating
Date (MW) Mode
---------------------
Total PPL Share
- ---------------------------------------------------------------------------------------------------------------------------
Griffith AZ 2x2x1 2001 Combined Cycle 540 270 Natural Gas Baseload
- ---------------------------------------------------------------------------------------------------------------------------
Lower Mt. Bethel PA 2x2x1 2004 Combined Cycle 600 600 Natural Gas Intermediate
- ---------------------------------------------------------------------------------------------------------------------------
Starbuck WA 2 - 2x2x1 2005 Combined Cycle 1200 1200 Natural Gas Baseload
- ---------------------------------------------------------------------------------------------------------------------------
Wallingford CT 5 2001 Simple Cycle 225 225 Natural Gas Intermediate
- ---------------------------------------------------------------------------------------------------------------------------
Eden PA 2 2002 Simple Cycle 90 90 Natural Gas Peaking
- ---------------------------------------------------------------------------------------------------------------------------
Sundance AZ 10 2002 Simple Cycle 450 450 Natural Gas Peaking
- ---------------------------------------------------------------------------------------------------------------------------
West Earl PA 10 2003 Simple Cycle 450 450 Natural Gas Peaking
- ---------------------------------------------------------------------------------------------------------------------------
University Park IL 12 2002 Simple Cycle 540 540 Natural Gas Peaking
- ---------------------------------------------------------------------------------------------------------------------------
Upper Hanover PA 2 2002 Simple Cycle 90 90 Natural Gas Peaking
- ---------------------------------------------------------------------------------------------------------------------------
Kings Park NV 6 2003 Simple Cycle 270 270 Natural Gas Intermediate
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL 4,455 4,185
- ---------------------------------------------------------------------------------------------------------------------------
PPL has executed a master purchase agreement for the option on 66 LM6000
combustion turbine generators, some of which are intended for these announced
projects. PPL Global has also executed master agreements for the purchase of 66
SCR systems for NO(x) emissions control and 33 transformers for use at these
peaking facilities. These facilities are configured in generating blocks
consisting of two combustion turbine generators and SCR systems with one main
transformer. Each generating block will be have a nominal capacity of 90 MW.
The Griffith Energy Project is located on a portion of a 160-acre site located
just south of Kingman, AZ. The Griffith Energy Project is a 600 MW natural gas
fired, combined cycle electric generating station, consisting of two GE 7FA
combustion turbine generators, two heat recovery steam generators, one steam
turbine generator. The Project is being constructed pursuant to a fixed price
Construction Contract between Griffith and BVZ Power Partners -- Griffith dated
July 1, 1999. Griffith is responsible for funding the Western Area Power
Administration's ("WAPA") construction of transmission system improvements under
the Construction Agreement, dated June 15, 1999. The local infrastructure
improvements will include natural gas pipelines, a water supply system and well
field accessing the Sacramento Valley Aquifer, new access roads, as well as two
separate gas pipeline interconnections to the El Paso Natural Gas Company and
the Transwestern Pipeline Company pipelines.
A-10
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Lower Mount Bethel is under development and projected to he commercially
operating in January 2004. The project will be located on the property of PPL's
Martin's Creek Station, located in Northampton County, Pennsylvania. The Lower
Mount Bethel project will include a natural gas fired, a nominally rated 540 MW
combined cycle electric generating station, consisting of two Siemens
Westinghouse Power Corporation (SWPC) 501FD combustion turbine generators, two
heat recovery steam generators with duct burners, NO(x) and CO emission control
system, and one steam turbine generator. This power island equipment will be
provided under an equipment purchase contract with SWPC. The project is
evaluating bids for the engineering, procurement (non-power island equipment)
and construction of the facility. The new facility will be connected into the
adjacent Martins Creek 230 kV switchyard by extending the bus to add an
additional bay. All three prime movers will be connected to the switchyard via a
single bus and line. The facility will include a natural gas pipeline spur,
potable, service, and raw water lines as well as wastewater to the existing
Martin's Creek lines. A sanitary waste disposal system will be provided by the
EPC contractor via septic system. Natural gas will he provided by TRANSCO,
TETCO, and Columbia Gas from IEC along two laterals. One 6-mile lateral line
will be constructed to connect to the TRANSCO line while an existing lateral
that connects to the existing generating facility will be tied into the new
facility.
The Starbuck Generating Station is a nominal 1,200 MW combined cycle project
utilizing four GE 7FA combustion turbine generators. The site is located in
eastern Washington on the Snake River, approximately 50 miles north of Walla
Walla, WA. PPL has completed the initial siting/environmental studies and
expects to receive approval from Washington State in 2002. If the project
continues on schedule, it will enter construction in mid 2002 and be in
commercial operation by early 2005.
1.3.1.3 Nuclear Generating Assets
PPL owns 90% of Susquehanna Station, which is a two-unit station with boiling
water reactors. The balance of Susquehanna Station in owned by Allegheny
Electric Cooperative. The units at Susquehanna Station are relatively new,
having come on-line in 1983 (Unit 1) and 1985 (Unit 2). Units 1 and 2 have
summer capacity ratings of 1,090 MW and 1,092 MW, respectively. Like other
nuclear stations, Susquehanna Station provides baseload service. PPL's share of
the Susquehanna Station represents approximately 21% of PPL's existing domestic
electric generating capability. As the generating asset portfolio grows to
include the plants under development and officially announced, the share of
generating capability from the nuclear units decreases to 18% of the total
generating capability.
The key aspects of the Susquehanna Station are summarized in Table 1-3.
Table 1-3
Nuclear Generating Units
---------------------------------------------------------------------------------------------------------------------------
Station Name State Units In Type Rated Capacity Primary Fuel Operating
Service (MW) Mode
Date ----------------------
Total PPL
Share
---------------------------------------------------------------------------------------------------------------------------
Susquehanna 1 PA 1 1983 Boiling Water 1,090 981 Nuclear Baseload
Reactor
---------------------------------------------------------------------------------------------------------------------------
Susquehanna 2 PA 2 1985 Boiling Water 1,092 983 Nuclear Baseload
Reactor
---------------------------------------------------------------------------------------------------------------------------
TOTAL 2,182 1,964
---------------------------------------------------------------------------------------------------------------------------
A-11
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.3.1.4 Hydroelectric Generating Assets
PPL owns all or part of 21 hydroelectric generating stations located in
Pennsylvania, Montana, and Maine. The largest hydroelectric generating stations
are Safe Harbor (414 MW nameplate) and Holtwood (107 MW nameplate) in
Pennsylvania, and Kerr (212 MW nameplate) in Montana. Of the 21 stations, all or
wholly-owned by PPL except for Safe Harbor. PPL owns one third of Safe Harbor
Generating Company with the other two thirds owned by Baltimore Gas & Electric.
The total hydroelectric generating capability owned by PPL is 766 MW (summer
capability), over half of which is derived from the three largest stations. A
listing of PPL's hydroelectric assets is presented in Table 1-4.
Table 1-4
PPL Hydroelectric Assets
- ---------------------------------------------------------------------------------------------------------------------------
Station Name State Water Body Units Capacity (MW In Service Date
-----------------------------------
Nameplate Summer PPL Share
Capacity Capacity
- ---------------------------------------------------------------------------------------------------------------------------
Black Eagle MT Missouri River 3 21.28 18 18 1927
- ---------------------------------------------------------------------------------------------------------------------------
Cochrane MT Missouri River 2 48.00 54 54 1958
- ---------------------------------------------------------------------------------------------------------------------------
Ellsworth ME Union River 4 8.90 9.10 9.10 1919, 1924, 1937,
1938
- ---------------------------------------------------------------------------------------------------------------------------
Great Works ME Penobscot River 11 7.91 7.91 7.91 1911-1912, 1925,
1928, 1936, 1965,
1988
- ---------------------------------------------------------------------------------------------------------------------------
Hauser MT Hauser Lake 6 17.00 17 17 1911-1915
- ---------------------------------------------------------------------------------------------------------------------------
Holter MT Hotter Lake 4 50 50 1918
- ---------------------------------------------------------------------------------------------------------------------------
Holtwood PA Susquehanna River 10 107.20 101.00 101.00 1910-1914, 1924
- ---------------------------------------------------------------------------------------------------------------------------
Howland ME Piscataquis River 3 1.80 1.88 1.88 1916-1921
- ---------------------------------------------------------------------------------------------------------------------------
Kerr MT Flathead Lake 3 211.68 189 189 1938, 1949, 1954
- ---------------------------------------------------------------------------------------------------------------------------
Madison MT Madison River 4 9.00 9 9 1906-1908
- ---------------------------------------------------------------------------------------------------------------------------
Medway ME West Branch Penobscot 5 3.44 3.44 3.44 1923-1925
River
- ---------------------------------------------------------------------------------------------------------------------------
Milford ME Penobscot River 4 6.40 6.40 6.40 1942-1956
- ---------------------------------------------------------------------------------------------------------------------------
Morony MT Missouri River 2 45.00 48 48 1930
- ---------------------------------------------------------------------------------------------------------------------------
Mystic MT Mystic Lake 2 10.00 11 11 1925
- ---------------------------------------------------------------------------------------------------------------------------
Rainbow MT Missouri River 8 35.60 35 35 1910, 1917
- ---------------------------------------------------------------------------------------------------------------------------
Ryan MT Missouri River 6 48.00 60 60 1915-1916
- ---------------------------------------------------------------------------------------------------------------------------
Safe Harbor PA Susquehanna River 12 413.50 411.50 137.17 1931-1940, 1985-1986
- ---------------------------------------------------------------------------------------------------------------------------
Stillwater ME Stillwater River 4 1.95 1.95 1.95 1949
- ---------------------------------------------------------------------------------------------------------------------------
Thompson Falls MT Clark Fork River 7 91.95 86 86 1915-1917, 1995
- ---------------------------------------------------------------------------------------------------------------------------
Veazie ME Penobscot River 17 8.35 7.86 7.86 1914-1938
- ---------------------------------------------------------------------------------------------------------------------------
Wallenpaupack PA Lake Wallenpaupack 2 40.00 22.00 22.00 1926
- ---------------------------------------------------------------------------------------------------------------------------
West Enfield ME Penobscot River 2 13.00 13.00 6.5 1988
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL 121 1,047 1,163 882
- ---------------------------------------------------------------------------------------------------------------------------
The Montana and Maine assets were recently purchased from Montana Power and
Bangor Hydro, respectively. The Montana hydroelectric assets comprise
approximately 57% of PPL's installed hydroelectric capability. The Pennsylvania
hydroelectric assets comprise approximately 37% of PPL's installed hydroelectric
capability, with the Maine assets contributing the remaining 6%. The
hydroelectric assets owned by PPL represent 9% of the PPL's total domestic
generating
A-12
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
capability in 2001. This is projected to decrease to 6% by 2020 as additional
non-hydroelectric generating capability is added to PPL's generation portfolio.
Stone & Webster visited the three Pennsylvania hydroelectric stations and
obtained information on the various Maine hydroelectric assets. Safe Harbor and
Holtwood are located near each other on the Susquehanna River. Holtwood is a
run-of-the-river station, while Safe Harbor has some storage capacity and can
generate more electricity during on-peak hours. Wallenpaupack is located in
northeastern Pennsylvania and is supplied from a reservoir. The station is
unmanned and primarily provides peaking service due to the large storage volume
of the reservoir. The Maine hydroelectric stations are primarily
run-of-the-river facilities with limited storage capacity.
1.3.1.5 Summary Description of Electric Generating Assets
The Assets can be grouped into various categories, such as by the mode of
operation (baseload. intermediate, and peaking), and primary source of energy
(coal, natural gas/oil, nuclear, and water).
The generating capacity and generation in 2000 is shown in Figures 1-1 through
1-2 by mode of operation, and primary energy source. For purposes of this
analysis, baseload units are those that operate with capacity factors greater
than 60%. Peaking units are those units that operate with capacity factors of
less than 20%. Intermediate units are those units that operate between 20% and
60%.
Figure 1-1
Generating Capacity and Generation in 2000
by Mode of Operation
Generating Capacity in 2000 Generation in 2000
[PIE CHART] [PIE CHART]
5% - Intermediate 4% - Intermediate
22% - Peaking 3% - Peaking
73% - Baseload 93% - Baseload
Of PPL's total generation capacity in 2000, 73% is baseload, 5% is intermediate,
and 22% is peaking. The baseload generation capacity consists of the two nuclear
units, all the coal-fired units except Martins Creek Units 1 and 2, and most of
the hydroelectric units (Holtwood, Maine Hydros, and Montana Hydros). While
the baseload generation capacity represents 73% of PPL's
A-13
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
total generating capacity, the actual electricity generated by these baseload
units in 2000 accounted for 93% of the total electricity generated by PPL.
The primary sources of energy from a generating capacity and generation basis is
shown in Figure 1-2, On a generating capacity basis, the primary source of
energy is coal, followed by uranium (nuclear) and oil/gas. Coal fired generating
capacity accounts for 48% of PPL's total generating capacity. Nuclear and
oil/gas-fired generating capacity, both represent 22% of PPL's total generating
capacity. Hydroelectric generating capacity is the fourth source of energy and
accounts for 8% of PPL's total generating capacity.
Figure 1-2
Generating Capacity and Generation in 2000
by Primary Source of Energy
Generating Capacity in 2000 Generation in 2000
[PIE CHART] [PIE CHART]
8% - Hydroelectric 9% - Hydroelectric
22% - Nuclear 32% - Nuclear
22% - Gas/Oil 3% - Gas/Oil
48% - Coal 56% - Coal
The primary sources of energy for the electricity generated by PPL in 2000 was
coal and nuclear energy. Coal is the source of 56% of the total electricity
generated, while nuclear energy was the source for an additional 32% of the
electricity generated. Hydroelectric power is the next largest source of power
accounting for 9% of the total electricity generated by PPL. There was a limited
amount of electricity (3% of the total) generated from oil/gas in 2000. PPL has
480 MW of capacity in combustion turbines located throughout Pennsylvania and
over 1,600 MW of capacity in Martins Creek Units 3 and 4. The existing
combustion turbines and Martins Creek Units 3 and 4 operate as peaking units,
hence the low contribution to the total electricity generated in 2000.
In the future, it is expected that PPL's intermediate and peaking generating
capacity and generation will increase with the addition of new combined cycle
and simple cycle projects. With the addition of these projects, the source of
fuel for PPL's electric generating facility portfolio will shift somewhat as
most of the new generation is gas-fired.
A-14
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
As can be from the figures above, PPL's Assets are heavily baseloaded with a
large amount of coal-fired and nuclear generating. Over time, the addition of
intermediate and peaking gas-fired units will broaden the character of PPL's
electric generating facility portfolio.
Another element of growing diversity in PPL's electric generating portfolio is
the location of the Assets. The electric generating facilities transferred from
PPL were all located in Pennsylvania. With the acquisition of the Montana Power
facilities and the Bangor Hydro facilities, PPL has expanded their generation
base into other regions. This expansion is continuing with the development of
new projects in Arizona, Connecticut, Washington and New York.
The mode of operation and energy sources for PPL's generation portfolio in 2004
are shown in Figures 1-3 and 1-4 below. By 2004, all the development projects
included in the Financial Projections, with the exception of the Starbuck
Project in Washington, will be in operation. These figures illustrate the
changes that are occurring as a result of PPL's generating facility development
program.
Figure 1-3
Generating Capacity and Generation in 2004
by Mode of Operation
Generating Capacity in 2004 Generation in 2004
[PIE CHART] [PIE CHART]
8% - Intermediate 5% - Intermediate
31% - Peaking 3% - Peaking
61% - Baseload 92% - Baseload
A-15
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Figure 1-4
Generating Capacity and Generation in 2004
by Primary Source of Energy
Generating Capacity in 2004 Generation in 2004
[PIE CHART] [PIE CHART]
7% - Hydroelectric 8% - Hydroelectric
18% - Nuclear 29% - Nuclear
40% - Gas/Oil 11% - Gas/Oil
35% - Coal 52% - Coal
1.3.2 Condition of Electric Generating Assets
The condition assessments of the Electric Generating Assets are based on data
gathered, observations made, and interviews conducted during limited site visits
to the electric generating assets. Stone & Webster visited the following
electric generating stations in the summer and fall of 2000 in the course of
preparing the Report
o Brunner Island Station
o Conemaugh Station
o Holtwood Hydroelectric Station
o Keystone Station
o Martins Creek Station
o Montour Station
o Safe Harbor Hydroelectric Station
o Susquehanna Nuclear Generating Station
o Wallenpaupack Hydroelectric Station
In addition to the facilities listed above, representative sites for the various
combustion turbine types were visited during the same time period.
A-16
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The fossil-fired and hydroelectric stations acquired from Montana Power and from
Bangor Hydro were not visited in the initial review of PPL's generating assets.
At that time, a technical review of the electric generating stations acquired
from Montana Power had recently been performed by R.W. Beck as part of the debt
financing completed by PPL for the assets acquired from Montana Power. For the
initial review of PPL's generating assets, data from the R.W. Beck report was
used including the financial projections for PPL Montana.
Given the major changes in the power markets in the West since the time that the
R.W. Beck was prepared, the market forecast was updated by the Market
Consultant. In order to incorporate the revised market forecast into the
Financial Projections, Stone & Webster performed a limited review of the PPL
Montana assets. The limited review included site visits to the hydroelectric and
fossil-fired units in the summer of 2001.
The electric generating facilities that PPL acquired from Bangor Hydro represent
a small portion of the overall generation portfolio. Furthermore, Stone &
Webster staff involved in the PPL due diligence review for financing were
familiar with the Bangor Hydro assets. Due to the small contribution to the
overall portfolio and our familiarity with the assets, a limited due diligence
review was performed, which did not involve any site visits.
During the site visits undertaken in 2000 and 2001, visual inspections were
conducted to assess the apparent condition, plant cleanliness, overall
operability, and the effectiveness of plant maintenance programs. Stone &
Webster also interviewed key personnel including technical specialists, O&M
personnel, and plant managers. To the extent the information was available to
us, Stone & Webster reviewed the most recent inspection reports, outage and
overhaul reports, life assessment reports, and capital expenditure forecasts.
These observations, visual inspections, facility personnel interviews and
additional data have been used to update and complement the engineering
assessment reports that form the basis for the condition assessment and
remaining life evaluation. In addition, Stone & Webster interviewed and obtained
information from key engineering and management staff located at PPL's
headquarters in Allentown. Relevant information on PPL's approach to condition
monitoring and on PPL's environmental management programs was obtained during
these visits the PPL's headquarters facilities.
There are only a few technical issues that can lead to an abrupt or unpredicted
end of life of an electric generating station. These include the following:
o serious site flooding and other natural disasters;
o geotechnical problems such as severe settling; or
o catastrophic failure of a major component which causes substantial
collateral damage.
In addition, there are certain technical and environmental issues that affect
the economic viability of electric generating stations such as
o new restrictive air quality criteria such as additional limits on
nitrogen oxide ("NO(x)"), sulfur dioxide ("SO(2)"), fine particulate
(sub 2.5 microns), mercury, and air toxics emissions
o new limits on water use and discharge that would result in the need
to install cooling towers; and
A-17
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
o more restrictive fish passage requirements that would result in
costly modifications to hydroelectric dams.
The Electric Power Research Institute ("EPRI") has developed a plant asset
management strategy designed to provide methodology for reaching decisions that
maximize the value of plants with extended lives and avoiding stranded
investments. The EPRI methodology helps identify plant reinvestment
opportunities that maximize capital returns and control risk. Stone & Webster
used the EPRI methodology as a guide in preparing the condition assessments for
the fossil-fired electric generating units.
For the review of the Susquehanna Nuclear Generating Station, in addition to
visiting the site Stone & Webster reviewed relevant reports and data to permit
the evaluation and the subsequent reporting of results presented herein. Nuclear
Regulatory Commission (NRC) letters, compliance information, permits and
amendments, etc were included in the review by Stone & Webster. For nuclear
generating facilities, the focus of the technical due diligence review is
equally weighted between station specific analyses, such as the physical
condition of the equipment, and program evaluations.
For the review of the hydroelectric generating stations, in addition to the
review of PPL data on the condition of the plants, Stone & Webster reviewed
recent dam safety inspection reports prepared by FERC and relevant dam
relicensing information.
1.3.2.1 Existing Fossil Fuel-Fired Generating Assets
PPL's fossil fuel-fired steam electric plants in Pennsylvania are predominantly
baseloaded, coal-fired facilities. Of the nine wholly-owned units, Montour Units
1 and 2 and Brunner Island Unit 3 are PPL's flagship units. All three of these
units are supercritical, coal-fired units with a nominal rating of 750 MW.
These units are similar to the Keystone and Conemaugh units, which PPL jointly
owns with several other electric generation companies. The units at Conemaugh,
Keystone, Montour, and Brunner Island are among the premier coal-fired units in
the PJM system.
The existing fossil-fired generating assets inspected by Stone & Webster were
found to be in average to better than average condition for units of a similar
age and use. PPL has made substantial investments in its coal-fired fleet. In
the mid-l990's low NO(x) burners were installed in the coal-fired units. The low
NO(x) burner operation for Montour Units 1 and 2 and for Brunner Island Unit 3
have resulted in increased tube wastage in the furnace waterwalls. Similar
problems were encountered by the operators of the Keystone and Conemaugh
Stations. Addressing the increased tube wastage problem has required the
expenditure of significant funds by PPL. PPL and the operators of the Keystone
and Conemaugh Stations have developed state-of-the-art strategies for addressing
the tube wastage problems. Presently, the programs implemented to address these
problems are in their final phases and appear to be successful in resolving the
problems.
PPL has installed additional air pollution control equipment -- selective
catalytic reduction (SCR) for NO(x) control and new electrostatic precipitators
(ESP) for enhanced particulate matter control -- at one of its coal-fired
stations (Montour). The first phase of the project was completed successfully in
June 2000 when the SCR system and ESP for Unit 2 went into service. The second
phase, the SCR system and ESP for Unit 1, was in service by June 2001. These and
other projects planned by PPL indicate a high level of commitment to the
continued reliable operation of the fossil fuel-fired units in Pennsylvania.
A-18
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Since our site visits to the Pennsylvania facilities, a number of events have
occurred or taken place which bear discussion. First, both Martins Creek Unit 1
and Brunner Island Unit 3 had major outages in the fall of 2000 and Montour Unit
1 was overhauled in the spring of 2001. The tie-in of the SCR and new ESP was
also accomplished during the Montour Unit 1 outage.
In March 2001, a fire occurred at Brunner Island Unit 3. The fire started when
the maintenance staff at Brunner Island opened an access panel on the Unit 3B
boiler feed pump turbine to investigate a suspected leak of oil used to control
the operation of the pump. The control oil line to the pump had ruptured and the
leak was more substantial than anticipated by the maintenance staff. With the
access panel open the oil spread quickly out of the pump and ignited when it
contacted non-insulated steam piping inside the boiler feed pump turbine
enclosure. The fire that erupted quickly spread from the turbine enclosure to
the Unit 3 mezzanine level. There were no serious injuries or environmental
effects from the oil leak and fire. However, the facility and Unit 3 itself
sustained severe damage in several areas. Unit 3 has been out of service since
the fire. PPL has indicated that it expects the repairs to be complete and Unit
3 to he back in service in September 2001. PPL has estimated the damage to Unit
3 to he approximately $40 million. However, PPL expects a recovery under its
business interruption/extra expense insurance policy that will significantly
offset the financial impact of the outage. The Financial Projections for 2001 do
not reflect the extended outage of Brunner Island Unit 3.
As part of the repair and restart of Brunner Island Unit 3, much of the major
rotating equipment was opened up and inspected. The control oil for the boiler
feed pump is also used as lubricating oil for the generator and turbine
bearings. During the extended outage for Unit 3, some repairs planned for the
next major outage (fall 2003) were performed which will delay the need for some
of the repair projects planned for that outage.
In addition to the coal-fired generation assets, PPL owns two 850 MW gas and oil
fired units (Martins Creek Units 3 and 4). Over the last several years, PPL has
proactively maintained these units by replacing or repairing aging components
and by modifying the units to allow for increased operational flexibility (i.e.,
adding dual fuel capability, etc.). While these two units are not projected to
be dispatched in the analysis prepared by the Market Consultant, they represent
a large and flexible source of energy and capacity.
The two PPL Montana stations -- Colstrip and Corette -- were recently visited by
Stone & Webster. The Corette Station has recently had a major outage, which
involved the replacement of substantial boiler components. The repairs made
during this outage should address some of the nagging reliability issues faced
by the Corette Station. In general, the condition and maintenance at the Corette
Station was found to be better than average for a facility of its age (built in
1968). Additional repairs to both the physical plant and improved operating
tools are also expected to continue to improve performance.
The condition of the four units at Colstrip Station was average. In recent
years, the station has been successful in reducing non-fuel operating costs,
which included large reductions in staff. At this time, the operating cost and
staffing are close to comparable facilities. With the operating costs under
control, PPL and the other owners are focused on improving the reliability of
the units without significantly increasing operating costs. Other large
coal-fired facilities have successfully gone through this process, which
requires a change in the maintenance approach from time-based maintenance to
condition based maintenance. If Colstrip can successfully implement these
changes to its operating philosophy, it can become one of the premier coal-fired
units in the western U.S.
A-19
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.3.2.2 Projects Under Development
The projects under development will be in new condition when they enter
commercial service. The technology used in the development of the various
combined cycle and simple cycle facilities is proven technology that is being
provided by major vendors, General Electric and Siemens Westinghouse.
1.3.2.3 Nuclear Generating Assets
The two units at Susquehanna Station were found to be in good overall condition.
Historically, the units have performed well with forced outage and availability
rates that are better than the average for similar units. The capacity factors
achieved by the Units 1 and 2 between 1995 and 1999 have average 84.0% for Unit
1 and 85.6% for Unit 2. The capacity factors during outage years have been in
the high 70% to low 80%. During non-outage years, the capacity factors have
average in the low 90% range. The projected capacity factor for the units is 85%
between 2001 and 2020, which is consistent with the recent experience. In
general, the capacity factors at nuclear units have been improving and it is
reasonable to expect that the capacity factors for the Susquehanna units may
improve as well. The largest area for improvement is in the duration of the
refueling outages.
The units are approaching the mid-point of their license period and have certain
balance of plant equipment that will need to be replaced in the near future. PPL
has included these replacements in its plans for the Susquehanna Station. In
addition, the units have had on-going problems with turbine blade erosion from
wet steam. These problems are similar to that experienced with other GE turbines
installed on nuclear units. PPL has budgeted the replacement of major elements
of the steam path (the LP turbines and parts of the HP turbines) with equipment
that is more resistant to erosion damage.
PPL is planning on completing two projects that will increase the generating
capability of the two units at Susquehanna. The first is a standard uprate of 11
MW at each unit that results from steam flow meter modifications. Modification
to the flow meters will allow PPL to operate the units closer to their rated
thermal capacities and thereby increase the generation from the units. The
second uprate is 40 MW for each unit gained through the turbine steam path
replacement. The flow meter uprates will be completed by the spring of 2002. The
turbine replacement projects will be completed by the spring of 2004.
Since our initial review, Susquehanna Unit 2 conducted its 10th refueling outage
in the spring of 2001. The outage was completed in 44 days against a target of
39 days. The outage was extended to address numerous maintenance tasks,
including re-work of seven Main Steam Isolation Valves (MSIV). Numerous other
inspections and overhauls were performed on nuclear and balance of plant
systems. About 1100 preventive maintenance work tasks were completed. The extent
of work accomplished during the outage will help support reliable operation
during the operating cycle.
NRC, internal and other assessments of the performance of the Susquehanna
Station have generally been good, with areas requiring improvements noted. On
May 30, 2001 NRC issued its annual assessment letter For Susquehanna, which
included inspection results for the quarter ending March 31, 2001. Overall, The
NRC concluded that the plant was operated in a manner that preserved public
health and safety and fully met all cornerstone objectives. There was one
finding of low to moderate safety significance (White) in the Occupational
Safety cornerstone. In a prior letter of December 12, 2000, NRC described a
related concern with the work environment within the radiation protection
organization and requested PPL's assessment of this situation and actions
A-20
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
planned to ensure that a safety-conscious work environment was maintained at
the plant. Based on the information provided by the station management, the NRC
has concluded that no increase in inspection frequency was warranted.
PPL also issued a Summary Assessment Report prepared by its Independent Safety
Engineering Group on February 16, 2001. The assessment provides an independent
assessment of the company's nuclear operations during 2000 from the nuclear
safety perspective. For the year 2000, there were no scrams or unanticipated
power transients. This level of transient performance is excellent and the best
in station history. All but one transient condition was caused by equipment
failures. The prior year assessment was issued on June 12, 2000. In this
assessment, PPL concluded that, although the station was operated competently
and safely during 1999, expectations of excellent performance during 1999 were
not met, and nuclear safety needs improvement. PPL is currently implementing
measures to address these issues as well as the areas identified for
improvement in the year 2000 assessment report.
1.3.2.4 Hydroelectric Generating Assets
Stone & Webster visited Holtwood, Safe Harbor and Wallenpaupack hydroelectric
stations. Holtwood and Safe Harbor are both located on the Susquehanna River,
with Holtwood Station located directly downstream of Safe Harbor Station.
Holtwood and Safe Harbor Stations are operated in a coordinated manner to
maximize the generation from both stations. Wallenpaupack is an automated and
unmanned facility located on a lake in northeastern Pennsylvania.
Over half the hydroelectric turbines at Holtwood Station have been replaced
since the original installation. The Unit 5 turbine is scheduled for replacement
in 2001. Additional replacement/upgrades are planned. PPL has replaced most of
the electrical equipment at Holtwood. The dam structure at Holtwood appeared to
be in acceptable condition. Additional inflatable rubber headboards are also
planned to be installed in 2001. The powerhouse structure had visible cracks
caused by alkali-silica reaction. None of the cracks appeared to be recent and
are being carefully monitored by plant staff. PPL has successfully demonstrated
to FERC that the Holtwood dam is a low hazard structure.
Safe Harbor Station was found to be in excellent condition during our site
visit. Units 1 through 7 were installed between 1931 and 1940 and Units 8
through 12 were installed in 1985. Much of the original electrical equipment has
been replaced or upgraded. The dam and powerhouse structures were found to be in
excellent condition with evidence of an on-going concrete repair program. Both
Holtwood and Safe Harbor Stations have recently had fish lifts installed.
Wallenpaupack Station dates from 1924 and was found to be in good condition
during Stone & Webster's site visit. The powerhouse is connected to the dam by a
3.5 mile long penstock. While the turbines are original equipment, they appeared
to be in good condition. Much of the electrical equipment and controls in the
powerhouse are relatively new or has been upgraded recently. The dam structures
appeared to be in good condition.
The hydroelectric assets in Maine were not visited by Stone & Webster. These
assets individually represent a very small portion of the total generation owned
by PPL.
The hydroelectric assets in Montana are significant assets, but were not
initially reviewed by Stone & Webster. Stone & Webster recently completed site
visits to the Montana hydroelectric stations. The Montana hydroelectric projects
were found in good to excellent condition with little need for any structural
repair at any facility. Each station visited was well maintained, equipment was
well painted and in good operating condition. The electric power systems were
also found to
A-21
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
be in good condition with evidence of recent upgrades such as power cable and
control cable replacement, and new digital electro-hydraulic governors for the
generators.
Some of the units are beginning to experience increased forced outages and
reduced availability. PPL is developing a program to upgrade and replace many of
the generators and transformers at the plants, in combination with other
upgrades such as turbine runner replacements. There is a significant potential
for hydraulic upgrades in many locations within the system that could result in
significantly increased electric production with relatively modest expenditures.
Preliminary estimates based on discussion with PPL Montana staff and review of
available data suggest that a 15 to 20 percent increase in the existing
hydroelectric capacity and annual electrical production is possible.
There are two items observed during our site visits that can affect reliability
and will require a modest amount of additional investment to repair. The first
item is the out-of-service tram at Mystic station Maintenance of any
significance can not be performed on the flow line, penstock, railway, intake
gate or dam or stanchion bays without the tram being in service unless
helicopter services are requested. Because such a request would he considered
extreme we believe that important maintenance is being delayed while the tram
issue is being resolved.
The second item is related to the transmission system from Black Eagle, Morony,
Ryan, and Cochrane Stations. The transmission lines are strung on wooden H frame
poles that are beyond their useful life. Many of these poles have been stubbed
but were reported by station staff to also be rotted. Additional surveys are
required to quantify remedial action.
1.3.3 Remaining Life of Assets
There are only a few technical issues that can lead to an abrupt or unpredicted
end of life of an electric generating station. In most cases, decisions to
retire generating units are made for economic reasons, which may be the result
of technical or environmental issues. While there is little or limited
experience with the operation of electric generating stations for 60 to 70
years, the technical factors, which may cause a unit to be retired are well
known. The primary technical reasons that would cause units to be retired are
likely to be fatigue and creep damage to major components such as the boiler and
turbine-generator. These potential aging and failure mechanisms can be detected
and monitored utilizing appropriate non-destructive testing techniques.
Table 1-6 shows the current age and estimate remaining life of the major
fossil-fuel, nuclear, and hydroelectric generating units reviewed by Stone &
Webster. Some of the PPL's fossil fuel-fired electric generating units have
accumulated sufficient operating hours to begin to show unrepairable damage to
high temperature components. PPL has a comprehensive condition monitoring
program and has replaced or is planning on replacing many high temperature
components. With continued monitoring and proper operation and maintenance,
PPL's major fossil fuel-fired electric generating stations (Brunner Island,
Martins Creek, and Montour) have a remaining life of at least 20 years.
Similarly, the nuclear units at Susquehanna have been well maintained with key
investments planned in critical components such as the turbine generator. The
Susquehanna units have a remaining life through the end of the current license
period, which is 2022 for Unit 1 and 2024 for Unit 2. With relicensing, these
units may have a remaining life of up to 40 years.
The hydroelectric units range in age from 12 to 90 years old. The hydroelectric
plants inspected by Stone & Webster should, with continued maintenance and
attention by PPL, have a remaining
A-22
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
life of at least 20 years. It is also likely that the hydroelectric assets in
Maine will also have a useful life of at least 20 years, again given proper
maintenance and attention.
The new combined-cycle and simple-cycle units are typically designed for useful
lives of thirty years or more.
Table 1-5
Remaining Life of Major Generation Assets
- --------------------------------------------------------------------------------
Station Unit In-Service Date Current Age Estimated
(Years) Remaining Life
(Years)
- --------------------------------------------------------------------------------
Brunner Island 1 1961 39 20+
2 1965 35 20+
3 1969 31 20+
- --------------------------------------------------------------------------------
Conemaugh 1 1970 30 20+
2 1970 30 20+
- --------------------------------------------------------------------------------
Keystone 1 1967 33 20+
2 1968 32 20+
- --------------------------------------------------------------------------------
Martins Creek 1 1954 46 20
2 1956 44 20
3 1975 25 20+
4 1977 23 20+
- --------------------------------------------------------------------------------
Montour 1 1973 27 20+
2 1973 27 20+
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Susquehanna 1 1983 17 20+
2 1985 15 20+
- --------------------------------------------------------------------------------
1.4 Performance
1.4.1 Approach
Stone & Webster provided key technical inputs on the performance capabilities of
the Assets to the Market Consultant and reviewed the Market Consultant's
projections for consistency with the technical inputs, PPL's operating plans,
and historical performance of the Assets. The projections developed by the
Market Consultant include net electricity generation, fuel consumption, and
number of starts.
The key performance parameters for the Assets depend on the type of generating
facility. Nuclear and hydroelectric units are typically operated at their
maximum capacity due to the low variable cost of generation. For nuclear units,
the amount of electricity generated is a function of the reliability or
availability of the unit. In the ease of nuclear generating facilities, the
availability factor for a Unit is very similar to the capacity factor since
nuclear units normally operate whenever they are available. Consequently, the
capacity factor is used as the primary measure of the performance of nuclear
units. Stone & Webster provided the Market Consultant with the average capacity
factor to be used for the Susquehanna units in the market projections.
The performance of hydroelectric units is typically limited by water flow rather
the reliability. Unless the generating characteristics of a hydroelectric units
has changed, the long-term average level of generation is a good starting point
for projecting the future performance of hydroelectric
A-23
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
stations. The annual electricity generation provided to the Market Consultant by
PPL is at or slightly lower than the long-term average electricity generation
achieved by the hydroelectric units.
For fossil-fired units, the key performance parameters are fuel efficiency,
reliability, responsiveness, and emissions. In the Market Consultant's
projections, each fossil-fired Unit is dispatched based on economic and
reliability factors. The key reliability factor is the outage rate due to both
planned and forced maintenance outages. The availability factor for each unit
can be calculated by taking the total net generating capability of the units
less the generation lost during forced and planned outages and dividing by the
total net generating capability of the units. If a unit were economically
dispatched 100% of the time, the availability factor would represent the maximum
capacity factor that the units could achieve.
The fuel cost is calculated from the fuel usage and the fuel price. The fuel
usage is a function of the fuel efficiency or net plant heat rate of the unit.
The net plant heat rate, which is expressed as the amount of fuel energy
required to generate 1 kWh of electricity, will vary depending on a number of
factors, including the load at which a fossil fuel-fired electric generating
Unit is operated. Typically, the heat rate of a Unit is optimized at its full
load or capability. Stone & Webster reviewed the full load heat rate inputs for
the units. The review consisted of an analysis of recent heat rate test data,
unit design data, and unit condition.
For each unit, the historical performance was reviewed for the period 1994
through 1999. Where appropriate, we have compared each unit's performance
against historical availability statistics compiled by the North American
Electric Reliability Council ("NERC"). The NERC data is organized by size of
unit and the type of fuel fired. The most recent data available is for 1998.
The following definitions of terms were used to define the performance data
presented for each unit:
Net Capacity Factor (NCF) - The NCF is equal to the net generation divided
by the product of the period hours and the net maximum capacity of the
unit. The net generation is the actual number of electrical megawatt hours
generated by the unit during the period being considered less any
generation (MWh) utilized for that unit's station service or auxiliaries.
The net maximum capacity is the maximum capacity (MW) a unit can sustain
over a specified period of time when not restricted by seasonal or other
deratings less the unit capacity (MW) utilized for that unit's station
service or auxiliaries.
Equivalent Availability (EAF) - The EAF is equal to the available hours
less the equivalent derated hours divided by the period hours. The
available hours is period hours less the planned, maintenance, and
unplanned hours. The equivalent derated hours is the product of the
planned, unplanned and seasonal derated hours and the size of the
deratings, divided by the net maximum capacity.
Equivalent Forced Outage Rate (EFOR) - The EFOR is the sum of the forced
outage hours and the equivalent forced outage hours divided by the sum of
the forced outage hours, the equivalent forced outage hours during reserve
shutdowns, and the service hours. The equivalent forced outage hours is
the product of the forced derated hours and the size of the deratings,
divided by the net maximum capacity. The equivalent forced outage hours
during reserve shutdowns is the product of the forced derated hours during
reserve shutdowns and the size of the deratings, divided by the net
maximum capacity. Reserve shutdowns are when the Unit is available for
service but not electrically connected to the transmission system due to
economic reasons. Service hours are the hours a Unit is electrically
connected to the transmission system.
A-24
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Net Plant Heat Rate (Btu/kWh)
The heat input to the unit over a period of time divided by the net unit
generation over the same period of time.
The historical and projected capacity factors for the electric generating assets
are shown in Table 1-6.
The coal-fired units at Brunner Island and Montour and the units at Conemaugh
and Keystone are projected to operate as baseload units with capacity factors
between 87% and 80%. The units at Conemaugh, Keystone, and Montour are projected
by the Market Consultant to be dispatched all hours that the units are not down
for planned, scheduled, and forced outages (i.e., the theoretical maximum
dispatch). For Conemaugh and Keystone the projected capacity factors are 87%
over the next twenty years. For Montour, the projected capacity Factor is 82.5%
over the next twenty years. Unit 3 at Brunner Island is also projected to be
dispatched at the theoretical maximum over the next twenty years. The projected
capacity factors for the two smaller coal-fired units at Brunner Island ranges
from 84% to 61%. The two coal-fired units at Martins Creek, which are smaller
and less efficient than the other coal-fired units, are projected to operate at
capacity factors of between 82% and 40%.
The three combined cycle facilities (Griffith, Lower Mount Bethel, and
Starbuck) are projected to be dispatched as either baseload or intermediate
units. Both of the combined cycle plants in the west (Griffith and Starbuck)
are projected to operate as baseload units with average capacity factors of
approximately 70%. The Lower Mount Bethel facility is projected to operate in
the intermediate range with an average capacity factor of approximately 50%.
The simple cycle units -- Wallingford, Sundance, University Park, Kings Park,
West Earl, Eden, and Upper Hanover -- are projected to operate in the high
peaking to low intermediate range. The combustion turbines used on all the
simple cycle units are the GE LM6000 PC Sprint machines. These are
aeroderivative engines which are very efficient, have a rapid response rate,
and are not affected by the number of starts as much as industrial frame
turbines are.
Historically, Susquehanna Units 1 and 2 have operated reliably, with capacity
factors above the industry average for similar sized boiling water reactor
units. The projected capacity factors for the Susquehanna units are consistent
with this recent experience. PPL, like other operators of nuclear generating
facilities, has plans for improving the availability of its nuclear units by
reducing the duration of refueling outages, performing maintenance while the
units are on-line, and repairing/replacing/upgrading key components that affect
forced outages. As a result of these efforts, it is likely that the actual
capacity factors achieved by the Susquehanna units will exceed the values used
in the Financial Projections.
Holtwood and the Maine hydroelectric plants are run-of-the-river units and have
capacity factors of 64% and 63% respectively. Safe Harbor and Wallenpaupack
operate more as peaking units and have capacity factors of 29% and 20%,
respectively. The projected performance of the hydroelectric units is based on a
long-term average of the river flows. While the actual capacity factors achieved
each year will vary based on variations in river flows, on average the capacity
factors achieved by the hydroelectric units should be consistent with the
long-term average river flows.
The projected performance of the Montana hydroelectric units are also based on
long-term average flows in the watersheds. The exception is 2001 where the
Market Consultant reduced the generation to reflect drought related loss of
generation. A number of plant upgrades are being
A-25
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
planned for the Montana hydroelectric units, which are expected to increase the
generating capacity by approximately 100 MW.
A-26
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-6
Historical and Projected Capacity Factors
- ------------------------------------------------------------------------------------------------------------------
1995 - 2000 2001 - 2020
- ------------------------------------------------------------------------------------------------------------------
Capacity Factors
- ------------------------------------------------------------------------------------------------------------------
Avg. EAF Avg. Capacity
Factor EAF 2001 2003 2005 2010 2015 2020
- ------------------------------------------------------------------------------------------------------------------
EXISTING FOSSIL FIRED UNITS
- ------------------------------------------------------------------------------------------------------------------
Montour Unit 1 79.3 65.0 82.5 82.5 82.5 82.5 82.5 82.5 82.5
- -----------------------------------------------------
Montour Unit 2 80.8 68.8
- ------------------------------------------------------------------------------------------------------------------
Brunner Island Unit 1 85.4 60.3 84.1 84.1 79.8 84.1 84.1 63.0 61.4
- -----------------------------------------------------
Brunner Island Unit 2 86.6 61.8
- ------------------------------------------------------------------------------------------------------------------
Brunner Island Unit 3 82.9 64.3 84.0 84.1 84.1 84.1 84.1 84.1 84.1
- ------------------------------------------------------------------------------------------------------------------
Martins Creek Unit 1 83.0 46.2 81.5 64.7 57.1 65.6 62.6 41.8 54.6
- -----------------------------------------------------
Martins Creek Unit 2 78.3 43.0
- ------------------------------------------------------------------------------------------------------------------
Martins Creek Unit 3 78.4 8.6 80.0 0.0 0.0 0.0 3.1 0.0 0.0
- -----------------------------------------------------
Martins Creek Unit 4 77.1 9.1
- ------------------------------------------------------------------------------------------------------------------
Conemaugh Unit 1 87.1 83.0 87.0 87.0 87.0 87.0 87.0 87.0 87.0
- -----------------------------------------------------
Conemaugh Unit 2 85.8 81.3
- ------------------------------------------------------------------------------------------------------------------
Keystone Unit 1 88.1 84.5 87.0 87.0 87.0 87.0 87.0 87.0 87.0
- -----------------------------------------------------
Keystone Unit 2 90.1 86.3
- ------------------------------------------------------------------------------------------------------------------
Existing CT's (less than) 1 0.0 0.0 0.0 0.0 0.0 0.0
- ------------------------------------------------------------------------------------------------------------------
Wyman Unit 4 17.0 0.0 0.0 0.0 0.0 0.0
==================================================================================================================
Colstrip Unit 1 86.2 86.2 86.2 86.2 86.2 86.2 86.2
- -----------------------------------------------------
Colstrip Unit 2
- -----------------------------------------------------
Colstrip Unit 3
- ------------------------------------------------------------------------------------------------------------------
Corette Unit 1 87.8 87.8 87.8 87.8 87.8 87.8 87.8
==================================================================================================================
NEW FOSSIL FIRED UNITS
- ------------------------------------------------------------------------------------------------------------------
Wallingford 97 3.5 17.8 24.1 18.4 16.1 10.8
- ------------------------------------------------------------------------------------------------------------------
King Park 97 32.6 23.5 15.4 16.2 11.7
- ------------------------------------------------------------------------------------------------------------------
PA Peaking Plants 97 9.6 13.9 15.1 13.9 11.7
- ------------------------------------------------------------------------------------------------------------------
Sundance 97 15.9 10.2 10.6 24.5 28.3
- ------------------------------------------------------------------------------------------------------------------
University Park 97 9.2 10.3 18.4 28.2 21.7
- ------------------------------------------------------------------------------------------------------------------
Griffith 92 42.0 73.4 64.8 70.8 77.0 78.1
- ------------------------------------------------------------------------------------------------------------------
Lower Mount Bethel 92 50.6 57.2 51.8 46.9
- ------------------------------------------------------------------------------------------------------------------
Starbuck 92 91.8 82.5 68.1 67.0
==================================================================================================================
NUCLEAR GENERATING UNITS
- ------------------------------------------------------------------------------------------------------------------
Susquehanna 1 85.2 83.5 88.3 88.3 88.3 88.3 88.3 88.3
- -----------------------------------------------------
Susquehanna 2 88.4 87.3
==================================================================================================================
HYDROELECTRIC UNITS
- ------------------------------------------------------------------------------------------------------------------
Holtwood 62.0 64.3 64.3 64.3 64.3 64.3 64.3
- ------------------------------------------------------------------------------------------------------------------
Safe Harbor 30.0 29.2 29.2 29.2 29.2 29.2 29.2
- ------------------------------------------------------------------------------------------------------------------
Wallenpaupack 21.2 20.2 20.2 20.2 20.2 20.2 20.2
- ------------------------------------------------------------------------------------------------------------------
Maine Hydro 63.1 63.5 63.5 63.5 63.5 63.5 63.5
==================================================================================================================
Montana Hydro
- ------------------------------------------------------------------------------------------------------------------
A-27
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.5 Operation and Maintenance
Information for the operation and maintenance review was gathered by Stone &
Webster from site visits to the plants and PPL headquarters. The data collected
during the plant site visits included staffing levels and positions and
maintenance management plans. The data collected from PPL headquarters included
the actual and projected O&M expenses and capital expenses.
1.5.1 Existing Fossil Fuel-Fired Generating Assets
No major staffing or operational changes are anticipated for the operation and
maintenance of the PPL fossil fuel-fired units. As shown in Table 1-7, the
projected 2001 O&M expenses for Montour and Brunner Island are similar to that
projected for Conemaugh and Keystone, which are benchmarks for large coal-fired
stations. The Conemaugh O&M expenses include the cost of operating and
maintaining scrubbers. Both the Conemaugh and Keystone O&M expenses include
certain general and administrative costs that are not included in the O&M
expenses for the wholly-owned PPL plants.
Table 1-7
Existing Fossil Fuel-Fired Station O&M Expenses
- ----------------------------------------------------------------------------------------
Brunner Island Montour Martins Creek Conemaugh Keystone
- ----------------------------------------------------------------------------------------
Actual 1997 36,213 35,264 23,045 58,967 41,120
- ----------------------------------------------------------------------------------------
Actual 1998 35,572 35,833 24,479 59,682 38,258
- ----------------------------------------------------------------------------------------
Actual 1999 38,139 38,517 26,593 58,804 40,529
- ----------------------------------------------------------------------------------------
Revised Budget 2000 40,566 41,157 25,929 58,536 41,231
- ----------------------------------------------------------------------------------------
Baseline 2001 41,500 42,000 27,000 64,084 45,050
- ----------------------------------------------------------------------------------------
The major operations and maintenance challenge is at Conemaugh and Keystone
where a significant number of operating and maintenance staff are likely to
take early retirement. The early retirement plan was put in place as part of the
sale of the GPU assets. GPU was one of the owners of the Conemaugh and Keystone
plants and was the operator. As part of the sale of its generating assets, it
offered an early retirement plan to its employees involved in the operation and
maintenance of the generating facilities. Maintaining the high level of
performance at Conemaugh and Keystone will be difficult until replacement staff
are trained and gain experience at the two stations. While the wholly-owned PPL
plants have a similar work force, an early retirement plan is not in place.
PPL has made substantial investments in its coal-fired fleet. In the mid-1990's
low NO(x) burners were installed in the coal-fired units. The low NO(x) burner
operation for Montour Units 1 and 2 and for Brunner Island Unit 3 have resulted
in increased tube wastage in the furnace water walls. Similar problems were
encountered by the operators of the Keystone and Conemaugh Stations. Addressing
the increased tube wastage problem has required the expenditure of significant
funds by PPL. PPL and the operators of the Keystone and Conemaugh Stations have
developed state-of-the-art strategies for addressing the tube wastage problems.
Presently, the programs implemented to address these problems are in their final
phases and appear to be successful in resolving the problems.
In addition to the coal-fired generation assets, PPL owns two 850 MW gas and oil
fired units (Martins Creek Units 3 and 4). Over the last several years, PPL has
proactively maintained these
A-28
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
units by replacing or repairing aging components and by modifying the units to
allow for increased operational flexibility (i.e., adding duel fuel capability,
etc.). While these two units are not projected to be dispatched in the analysis
prepared by the Market Consultant, they represent a large and flexible source of
energy and capacity.
With the installation of two SCR systems and the replacement of the existing
ESP's at Montour, PPL has undertaken a complex and intensive construction
project. The first phase of the project was completed successfully in June 2000
when the SCR system for Unit 2 went into service. The second phase, the SCR
system for Unit 1, is expected to be in service by June 2001. The SCR systems
are only one of the major projects implemented or planned by PPL for its units
in Pennsylvania. The projects planned by PPL indicate a high level of commitment
to the continued reliable operation of the fossil fuel-fired units in
Pennsylvania.
1.5.2 Projects Under Development
For the new projects, only the Griffith Energy Project has firm staffing plans
as they have hired Primesouth as the operator of the facility. Primesouth
expects to staff the facility with 21 permanent, full-time persons. Stone &
Webster believes this staffing level is reasonable and typical of a stand alone
combined cycle of configured similarly to the Griffith Energy Project. The
Lower Mount Bethel Project intends to utilize staff from the Martins Creek,
however Stone & Webster has not been provided a detailed staffing plan. The
staffing for the peaking plants, including Wallingford, will have staffs much
smaller than the two combined cycle plants and will reflect the lower staffing
requirements for peaking operation. Although Stone & Webster has not reviewed
staffing plans for the peaking plants, there is sufficient funds budgeted to
cover the expected staffing requirements of a peaking plant. In general PPL
intends to follow the overhaul recommendations provided by the original
equipment manufacturers. Griffith Energy and Lower Mount Bethel have executed
long term service agreements, which provide for the execution of the major
maintenance required. Most of the major maintenance cost projections for
Griffith Energy and Lower Mount Bethel are based on the payments required by the
respective service agreements.
1.5.3 Nuclear Generating Assets
The operation and maintenance staffing, approach, execution and expenses for the
Susquehanna Station are similar to that observed by Stone & Webster at similarly
sized and configured nuclear generating stations. PPL, as noted earlier, is
addressing certain deficiencies in its operation and maintenance practices,
which are causing a short-term increase in its O&M expenses. Prior to this, the
O&M expenses for the Susquehanna Station were approximately 5% lower than the
benchmark annual O&M expense of $200 million. After these deficiencies are
addressed, the O&M expenses are again reduced but to a higher level than before
($200 million in 2000 dollars). The O&M expenses projected are reasonable and
achievable for a station such as Susquehanna.
PPL has and continues to invest in capital improvements to the Susquehanna
Station. Over the next several years, PPL has budgeted capital and expense funds
to address the deficiencies noted by the NRC. In addition, PPL is implementing a
project to achieve a 1% up-rate on both units and to address on-going
maintenance issues with the steam turbines.
1.5.4 Hydroelectric Generating Assets
No major changes are planned by PPL to the operation and maintenance of the
hydroelectric assets. The total O&M expenses for PPL's share of the Pennsylvania
and Maine hydroelectric
A-29
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
assets are $14 million in 2001. This level of O&M expenditure, though modest
compared to the nuclear and large fossil-fired assets, are sufficient to allow
the continued reliable operation of these hydroelectric assets.
1.6 Environmental Assessment
Stone & Webster prepared an overview of current air and water permit
requirements, environmental limitations on current or future operations,
environmental compliance, and other significant environmental issues affecting
the operation of the electric generating assets. The environmental assessment
prepared by Stone & Webster is based on the results of a review of available
documents, a plant walk-down, and interviews with key operating and staff
personnel.
To provide a background for the environmental assessment, key environmental
regulations and laws that govern air emissions and water discharges from the
electric generating facilities are described below.
1.6.1 Background Environmental Information
1.6.1.1 National Ambient Air Quality Standards
On July 16, 1997 the EPA published a final rule revising the National Ambient
Air Quality Standard (NAAQS) for particulate matter (PM) which adds PM(2.5)
(particles with an aerodynamic diameter less than or equal to a nominal 2.5
micrometers) to the regulation of PM. On the same day, the EPA also published a
final rule revising the NAAQS for ozone. Relative to the PM NAAQS, the EPA has
added a new 24-hour and an annual NAAQS for PM(2.5) (65 and 15 ug/m-3,
respectively). The EPA also revised the form for the existing 24-hour PM(10)
(particles with an aerodynamic diameter less than or equal to a nominal 10
micrometers) NAAQS. The EPA did not revise the magnitude of the annual PM(10)
NAAQS but did revise some aspects of the form of the standard in terms of how
compliance is determined. The revised NAAQS for ozone has an 8-hour averaging
period (versus 1 hour for the previous NAAQS) and the concentration has been
revised from 0.12 ppm to 0.08 ppm. These revised NAAQS are generally considered
to be more stringent standards than the previous standards resulting in more
"nonattainment" areas than under the previous NAAQS.
On May 14, 1999, the Court of Appeals for the District of Columbia Circuit, in
response to challenges filed by industry and others, held that the Clean Air
Act, as applied in setting the new public health air quality standards for ozone
and PM, is unconstitutional as an improper delegation of legislative authority
to the EPA. The U.S. Supreme Court has reversed this decision and has remanded
the matter to the Court of Appeals for the District of Columbia Circuit.
1.6.1.2 NO(x) State Implementation Plan (SIP) Call
On September 24, 1998, the EPA finalized a rule requiring 22 states and the
District of Columbia to submit SIPs to address the regional transport of
ground-level ozone. These SIPs will address reductions in NO(x) emissions from
utility boilers and non-utility point sources as a precursor to ozone formation.
The final EPA rule contains a state-by-state NO(x) emissions budget that applies
to the ozone season (May through September) and the states will have the
flexibility to decide which sources are controlled and by how much. However,
electric utilities, large industrial boilers and turbines, and cement plants
were considered by EPA in the development of the state budgets and will likely
be affected by the SIP revisions.
A-30
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
On September 30, 1999 the U.S. Court of Appeals for the District of Columbia
Circuit issued an order staying the portion of the NO(x) SIP Call which required
states to submit rules by September 30, 1999. On March 3, 2000, a three-judge
panel of the same court largely upheld the NO(x) SIP Call rule allowing the EPA
to move ahead with its plan. However, the panel did not specifically lift the
stay on the SIP submittals by the affected states to the EPA. On June 22, 2000
the D.C. Circuit Court of Appeals made a final ruling upholding the NO(x) SIP
Call, allowing EPA and the eastern states to move forward on a fixed schedule.
However, the deadline for compliance with the SIP Call was extended to 2004.
Regardless of the SIP Call outcome, utility sources in Pennsylvania must comply
with the Phase II and III requirements of the Ozone Transport Commission
("OTC") Memorandum of Understanding ("MOU") program agreed to in 1994. Phase II
became effective on May 1, 1999 and continues through 2002. Under Phase II of
the program, each state receives a number of NO(x) allowances each year, which
are allocated to individual sources, including the eligible sources. NO(x)
allowance allocations have been made to eligible sources for the 1999 ozone
season. At the end of each calendar year, each facility must have a number of
NO(x) allowances equal to or greater than the facilities' emissions from May 1
through September 30 of that year. Phase III of the OTC MOU begins in May 2003
and further reduces NO(x) emissions using a NO(x) allowance system based on an
emission rate of 0.15 pounds per million Btu. Again, this would be an ozone
season program only (May 1 through September 30).
1.6.1.3 Section 126 Petitions of the Clean Air Act Amendments of 1990 (CAAA)
Clean Air Act Section 126(b) authorizes states or political subdivisions to
petition the EPA for a finding that major stationary sources in upwind states
emit in violation of the prohibition of section 110(a)(2)(D), by contributing
significantly to "nonattainment" problems in downwind states. Beginning on
August 14, 1997, EPA received eight petitions under Section 126 from
Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode
Island, and Vermont. The petitions ask EPA to find that major sources of NO(x)
emissions in states in the eastern half of the United States, from (and
including) Louisiana in the southwest, Minnesota in the northwest, and Georgia
in the southeast, contribute significantly to ozone "nonattainment" in areas
further to the east and north.
In large part, EPA granted those petitions on January 18, 2000. The result of
this action is to require essentially the same reductions in seasonal NO(x)
emissions from 392 named facilities in 12 states and the District of Columbia as
would be required of those facilities under the SIP Call. These facilities
include the PPL assets located in Pennsylvania. Each affected facility will
participate in a federal NO(x) emissions cap-and-trade program administered by
the EPA. The facilities are initially allocated annual NO(x) allowances by EPA
for the period 2003 through 2007 based on heat input and a NO(x) emission rate
of 0.15 lb/MMBtu. Sources must implement controls or acquire emission allowances
to achieve their budgets by May 1, 2003. Updated allocations will be based on
output for electric generating units. These allowances may be bought, sold, or
traded between affected sources and other private parties.
1.6.1.4 Title IV - Acid Rain
Title IV of the CAAA requires that nationwide SO(2) emissions be reduced by 10
million tons per year and emissions of NO(x) be reduced by 2 million tons per
year from 1980 levels, both by the year 2000. Title IV provides for a two-phase
approach in meeting these reductions. Phase I applies to 110 electric utilities
with 263 units named in the CAAA and Phase II applies to all
A-31
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
utility units above 25 MW in the 48 contiguous states. Phase I began in 1995.
With respect to SO(2), the 263 affected units were required to reduce SO(2)
emissions to a number of allowances established in the CAAA equivalent to the
unit's annual average baseline fuel consumption from 1985 to 1987 and an
emission rate of 2.5 pounds per million Btu (Phase I allowances). Each allowance
represents one ton of SO(2). These allowances are a marketable commodity whereby
a unit that emits less than its allocated allowances may save the unused
allowances for future growth, transfer to other plants, or sale to other
utilities that exceed their allowance allocations With respect to NO(x), the
Phase I emission rate was established at .45 lb/MMBtu. Phase II started in the
year 2000. With respect to SO(2), the cap is reduced based on an emission rate
of 1.2 pounds per million Btu and the 1985 to 1987 baseline fuel usage. The EPA
has published a list of Phase II allocations to utility units that it believes
will be affected by Phase II. With respect to NO(x), the emission rate is
reduced to .40 lB/MMBtu.
1.6.1.5 Hazardous Air Pollutants
Under Title III of the CAAA, EPA has published a list of source categories
that will be required to implement controls for 188 hazardous air pollutants
("HAP"s). Electric utilities were deferred from regulation under Title III of
the CAAA until such time as EPA completed a comprehensive study on the public
health impact of the utility industry relative to HAP emissions and reported
the results to Congress. This utility report was completed in February 1998 and
submitted to Congress. EPA has determined that mercury emissions must be
regulated and is expected to develop regulations by 2004. It is impossible to
predict what mercury controls the EPA will ultimately require.
1.6.1.6 Regional Haze Initiative
The goal of the regional haze initiative is to reduce visibility impairment in
and around 156 Class I protected areas (e.g., pristine areas such as national
parks and wilderness areas) caused by fine particulate and other pollutants
(SO(2), NO(x), and volatile organic compounds "VOC"). States will need to
prepare SIP revisions that reduce and eventually eliminate existing visibility
impairment in and near Class I areas on the worst days and also prevents any
future impairment on the best days. The etiect of this rule will vary greatly
depending on the proximity of individual plants to Class I areas. However, the
time frame for implementation of any further controls for those that are
effected by this rule appears to be at least 6-10 years. There are no Class I
areas in Pennsylvania, but there are such areas in downwind states.
1.6.1.7 Global Warming - Greenhouse Gases
On December 11, 1997 in Kyoto, Japan, more than 150 countries came to an
agreement on target reductions of greenhouse gas emissions for the
industrialized nations of 6 to 8 percent from 1990 levels by the year 2012. The
next round of negotiations took place in Buenos Aires, Argentina in November
1998. These negotiations resulted in the Buenos Aires Action Plan which
established deadlines during the year 2000 for finalizing work on the Kyoto
Mechanisms (Joint Implementation, Emissions Trading and the Clean Development
Mechanism). There is much opposition to the treaty being expressed by industry
at this time. Therefore, it is difficult to ascertain the treaty's impact on
future power generation operations. However, the treaty will likely have some
effect, perhaps in terms of improved system operating efficiency and
encouragement of the use of clean fuels and renewable energy sources. Some form
of carbon emissions cap and allowance trading is also a possible outcome of this
process.
A-32
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.6.1.8 New Source Review Enforcement Actions
In the fall of 1999 EPA initiated enforcement actions against 32 coal-fired
power plants for alleged new source review (NSR) violations. EPA claims the
utilities failed to install appropriate emission control technologies following
various plant modifications.
EPA has issued information requests related to NSR activities to Conemaugh and
Keystone Stations and the Corette Station. EPA has not indicated what action
they will take concerning Conemaugh, Keystone or Corette. There have been no
further information requests for other PPL generating units.
1.6.1.9 Water Programs
There are issues in the administration of State and Federal water related
regulations that may affect the capital and operating budgets of electric
generating facilities throughout the United States, including items under the
Clean Water Act and SDWA as described briefly below:
Under the Clean Water Act
1) Tightening of state water quality standards and anti-backsliding
provisions,
2) Technology driven wastewater treatment improvements for specific
parameters and toxics,
3) Stormwater NPDES standards and implementation of watershed based
mitigation,
4) The impact of new municipal stormwater regulation on existing power
plant NPDES permits,
5) Loss of the 316 variance and the legal challenges to authority to
rescind a variance.
The loss of the 316 variance has the greatest potential impact on PPL at this
time. The generating units at Brunner Island and Martins Creek Units 1 and 2
have once through cooling systems. Many existing steam electric facilities with
once through cooling systems, even those that have operated for many years, are
required to prepare a 316 (a) and/or 316 (b) demonstration to ensure for the
regulating agency (regional EPA or state water authority) that continued
operation with the once through cooling system is appropriate. The 316
demonstration is a formal report prepared by the NPDES permit holder that shows
that once through operation is not adversely impacting the populations of plant
and animal species that are resident in the receiving water body. The agency
with NPDES authority may request such a study at any of the 5-year intervals
when the NPDES permit is reauthorized. Some steam electric facilities have been
requested to prepare a 316 demonstration when they have already prepared a
demonstration within the last 15 years that was, at that time, deemed adequate
by the agencies. An adequate demonstration can cost as much as $1 to $5 million
to prepare, submit and support, and require many years of field study, and
impingement and entrainment monitoring. A successful demonstration only ensures
that the project can continue with once through cooling for at least 5 more
years. However, it is common that the regulatory agency may require additional
capital expenditures for mitigation of operation of either the intake (e.g.,
fish friendly traveling water screens) or the discharge (e.g., diffusers or
discharge point relocation).
There are at least some owners of electric generating facilities with once
through cooling that are considering a legal challenge to the agency authority
to take away the original waiver that allowed the project to be built and
originally operated with a once through cooling system. This legal authority is
being questioned, because many owners recognize that the economics of their
A-33
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
energy facility are threatened if the project must incur the capital and
operational costs of backfitting a closed cycle cooling system. Some owners
also recognize the practical limitations of a backfitted closed cycle system,
including the operating efficiency penalties (e.g., increase in turbine
backpressure). This action is likely to be resolved in the next two years, but
there is no basis to determine how this potential action might affect the NPDES
status of any PPL once through steam electric generating facilities.
On May 7, 2000 EPA announced a change in their water quality standards program.
Until this time each state could define and implement their water quality
standards. These are the standards that any discharge to surface water must meet
either at the point of discharge or at the edge of an approved mixing zone for
the discharge.
From now on EPA must approve any new water quality standard proposed by a state
before they are applicable. EPA will now review any new standards with respect
to guidelines previously prepared by EPA. This means that any new or revised
water quality standards are more likely to be similar to standards for adjacent
or nearby states unless there is some good reasons for deviations from the EPA
guidelines.
A likely outcome from this change is changes in maximum allowed temperature
limits. Many states have very different standards for temperature that are also
very different from EPA guidelines. The guidelines identify species specific
criteria for fish, which generally have not been the criteria used by states
previously to set thermal limits on a discharge. Some changes in criteria are
expected and will affect the discharge limitations of many once through cooling
water discharge structures. It is not known when individual states would prepare
new water quality standards or when EPA would promulgate replacement water
quality standards that are equal to or more stringent than existing standards.
Under the Safe Drinking Water Act;
1) New goals for drinking water contaminants and their link to power
plant operations,
2) Sole source aquifer designation and state wellhead protection plans,
3) New regulations for Underground Injection Control Wells.
Based on discussions with PPL staff, these specific issues are not likely to
apply to the assets under evaluation.
Under State Law
o Regulation of water withdrawal
1.6.2 Summary of Environmental Assessment for Existing Fossil-Fired Units
Stone & Webster prepared an overview of current air and water permit
requirements, environmental limitations on current or future operations,
environmental compliance, and other significant environmental issues affecting
the operation of the electric generating assets. The environmental assessment
prepared by Stone & Webster is based on the results of a review of available
documents, a plant walk-down, and interviews with key operating and staff
personnel.
PPL has an environmental management infrastructure in-place that is capable of
managing existing environmental programs and of addressing new environmental
issues related to its core business. A clear example of PPL's capabilities in
this area is the implementation of the environmental retrofit project at
Montour.
A-34
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
PPL has plans to address future compliance with NO(x) and SO(2) emission limits
through additional environmental projects at Brunner Island and Montour
Stations. PPL's SO(2) compliance strategy is to use the S0(2) allowances it has
banked and eventually install scrubbers at Montour Station. Based on the
generation forecast developed by the Market Consultant, PPL would need to
purchase additional SO(2) allowances between 2005 and 2010, when the scrubbers
are planned to be on-line. The scrubbers could be operational as early as 2007
or 2008, if necessary. Ultimately, the decision to install scrubbers and the
time frame for the installation will be based on a number of factors including
the cost of purchasing allowances and future environmental regulations.
Based on the current set of assumption, after 2010, PPL would be generating
excess SO(2) allowances. With the installation of SCR systems at Montour, PPL
will be generating excess NO(x) allowances in 2001 and 2002. In 2003, it will
need to purchase additional NO(x) allowances to be in compliance. In 2005, an
SCR is tentatively scheduled to be completed for Brunner Island Unit 3, though
PPL is considering installation of SNCR on one or more of the units as an
alternative to the SCR. At that time, PPL would again become a generator of
excess NO(x) allowances.
The generating assets operated by PPL have current and valid permits and no
persistent history of violations. An overview of the permit status for the
major generating stations is as follows:
o Montour Station has been issued a draft Title V air permit from the
Pennsylvania DEP. A Notice of Violation for an opacity exceedance
was issued in 1999. With the replacement of the particulate control
equipment recently completed, this issue should be addressed
satisfactorily. An SCR system for NO(x) control and new ESP's for
particulate control were installed in 2000 for Unit 2. Similar
equipment has been installed on Unit 1 and is currently operational.
Montour's NPDES permit is current through September 2002. Both
bottom ash and fly ash generated at Montour are reused. There are
existing, permitted, on-site fly ash and bottom ash disposal
facilities that are used for off-spec material that cannot be
beneficially reused. Both of these disposal facilities have extended
(15+ years) remaining lives.
o Brunner Island Station has been issued a Title V air permit. There
have been no recent Notices of Violation or enforcement actions. The
NPDES permit is current through June 2001 with a timely renewal
application filing maintaining the applicability of the existing
permit conditions. A draft NPDES permit has been issued and contains
a provision requiring another demonstration under Part 316 of the
Clean Water Act that the plant's cooling water discharge does not
adversely impact fish in the Susquehanna River. There is an on-site
disposal facility for bottom ash, but not for fly ash. Brunner
Island has been successful in marketing almost all of its bottom and
fly ash for beneficial use.
o Martins Creek Station has been issued a Title V air permit. The
plant has experienced some opacity exceedances and is currently
negotiating a consent order with the Pennsylvania DEP. The new NPDES
permit was issued on August 6, 2001 and is current through August 5,
2006. There are existing, permitted, on-site fly ash and bottom ash
disposal facilities. Both of these disposal facilities have extended
(15+ years) remaining lives.
o Conemaugh Station has submitted a draft Title V air permit and
received a completeness determination from the Pennsylvania DEP. A
Notice of Violation was issued in 1999 for fugitive dust emissions
from the coal storage area. Conemaugh is equipped with flue gas
desulfurization ("FGD") equipment for SO(2) control. The NPDES
permit expired in September 1998. Conemaugh had submitted a NPDES
permit renewal application six
A-35
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
months prior to the expiration date and is operating under the
provisions of the expired permit. Conemaugh has received a number
of Notices of Violations and paid fines for exceeding the selenium
discharge limits in its NPDES permit. The selenium has been traced
to the coal that Conemaugh burns in the ozone season to limit its
NO(x) emissions. No proven technology exists for removing the
selenium from the discharge water. Conemaugh has an on-site ash
disposal facility and markets the residue from the FDG system.
o Keystone Station has submitted a draft Title V air permit and
received a completeness determination from the Pennsylvania DEP.
Keystone has a current NPDES permit. There have not been any recent
Notices of Violation or enforcement actions related to air emissions
or wastewater discharges. There is an on-site ash disposal facility
that will be filled in 2001. A landfill expansion is underway which
will provide for an additional 30 years of disposal capacity.
o Colstrip Station Unit 3 and 4 recently failed to meet its permitted
particulate matter emissions limits during a periodic emissions
compliance test. The amount by which the permit limit was exceeded
was small. Minor plant modifications were made and the units were
retested. The retest demonstrated that the units could achieve its
permit limits. PPL is expecting a Notice of Violation from the State
on this issue.
1.6.3 Summary of Environmental Assessment for New Development Units
The staff managing the construction of the Griffith facility have indicated that
all the necessary permits and approvals for construction were obtained for the
Griffith facility. However, it was not possible to verify this as all the
relevant information was not provided to Stone & Webster. All necessary permits
and approvals for construction were obtained for the Wallingford facility. The
new projects all have state-of-the-art emissions control equipment or have
provisions to add such equipment (such as oxidation catalysts for CO removal) in
the future if it is required.
1.6.4 Summary of Environmental Assessment for Nuclear Units
The major environmental permit required for Susquehanna Station, other than the
NRC license, is a NPDES permit. PPL has submitted an NPDES permit renewal
application that covers the entire facility for the period from June 22, 2000 to
June 21, 2005. This permit was to be issued after July 1, 2000 because PPL
sought to have the permit owner name changed from PP&L Inc to PPL Susquehanna,
LLC. Under prior NPDES permits, the Susquehanna Station operated with similar
discharge constraints to those included in the draft of the renewed NPDES
permit. There are no proposed discharge limitations cited in the draft permit
that should make compliance, compliance monitoring, and the monitoring reporting
required in the permit any more burdensome than required in the previous five
years of operation of this facility.
PPL is affiliated with the Appalachian States Compact Commission. PPL currently
has a one-year contract for disposal of low level radioactive waste with the
Barnwell Low Level Radioactive Waste Disposal Facility. The Barnwell facility is
the primary disposal facility used by PPL. Continued access to the Barnwell
facility will be dependent upon an allocation process that is currently being
developed. PPL has a low level radioactive waste storage facility at the
Susquehanna Station. This on-site facility has the capacity to store the
quantities of low level radioactive waste projected to be generated at the
Susquehanna Station through the end of the current license period.
A-36
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The Susquehanna Station spent fuel storage pool is fully racked. Based on
commitments to maintain space for a full core offload, PPL has installed an on
site dry storage facility. The on-site facility developed by PPL uses one of the
systems qualified by the NRC. Since the on-site storage facility has been
established, fuel storage campaigns have been scheduled, with the purchase of
the required storage canisters and storage modules. PPL began using the
dry-storage system in late 1999 for storing its used nuclear fuel at the power
plant until the federal government opens a central storage facility. Located
within the plant's security fence, the system is approved and licensed by the
NRC. Similar dry cask storage systems have been successfully used at other
nuclear plants in Maryland, South Carolina. Virginia, Colorado, Michigan,
Minnesota, Wisconsin, Ohio and Arkansas.
1.6.5 Summary of Environmental Assessment for the Hydroelectric Units
The hydroelectric assets have on-going requirements as part of their FERC
licenses. The general trend in the industry has been for more environmental
requirements, such as fish ladders, being imposed on hydroelectric plants. PPL
has installed fish ladders and other devices on some of its plants and has
budgeted for the installation of additional devices on its other hydroelectric
plants.
1.6.5.1 Holtwood
At Holtwood, the FERC exercised a standard license article included in every
FERC license to require PPL to design and install upstream fish passage
facilities. The Holtwood license also required PPL to study dissolved oxygen
concentrations in the tailrace of the facility. FERC and the State of
Pennsylvania expect the quality and quantity (on an instantaneous flow basis) to
meet the existing State water quality standards. The Holtwood license also
required that the existing leakage flow from the dam and powerhouse be
supplemented with an additional 50 cubic feet/second flow through a new 10 inch
pipe. Finally the license requires PPL to ensure that docks, pier, bulkheads,
and plantings constructed and maintained by others be done in a way that
preserves scenic, recreational, and other environmental values on the project
lands. These additional license requirements imposed some additional costs on
Holtwood. Future costs associated with these license requirements are shown in
the Financial Projections.
1.6.5.2 Wallenpaupack
The Wallenpaupack FERC license was issued in 1980 and expires in 2004. As with
the other hydroelectric projects, the Lake Wallenpaupack license includes a
general environmental reopener article that does not appear to have been used to
date. Because the project impoundment is well developed and the eutrophic
reservoir stratifies in the summer months, there has been an ongoing issue of
poor water quality in the reservoir and the project discharge. Low dissolved
oxygen, hydrogen sulfide releases, and turbidity of the reservoir and discharge
have been and continue to be studied. These studies are an ongoing cost to the
project.
As a part of the licensing process, PPL initiated the Wallenpaupack relicensing
with the FERC in 1999. PPL will also prepare an Applicant Prepared Draft
Environmental Assessment for submittal and processing by the FERC. PPL has
already developed scopes of work for studies of flows in the lower part of the
bypassed reach of river, flow releases below the tailrace and water quality in
the reservoir and points below the tailrace. The purpose of the flows in the
bypass reach is to evaluate the effect on fish habitat wetlands, recreation,
fish passage, and public safety. The purpose of the study of flow releases below
the tailrace is to evaluate the possible enhancements to fish habitat and
boating use.
A-37
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Enhancements to the water quality of the tailrace discharge may require some
form of turbine venting, aeration within the penstock, or oxygenation. These
type of enhancements require capital costs for construction and typically have a
small (1 to 3%) reduction in turbine efficiency. The capital costs would depend
on the type of system that is determined to be necessary at a future date based
on the ongoing and future water quality studies.
Although there have only been very limited flow releases to the bypass
throughout the history of Wallenpaupack, it is possible that studies currently
underway may identify a need to establish a permanent or season flow to the
bypass reach. Flows into the bypass may be required if the ongoing studies
demonstrate there would be valued enhancements to fish habitat, wetlands, fish
passage, water quality or boating. If the FERC finds the flows are required for
supporting wetlands or fish habitat this would likely require a continuous flow
and all the bypassed flows may be unavailable for generation. If the FERC finds
the flows are only necessary for boating or seasonal fish passage, those flows
may only be necessary in certain seasons of the year.
1.6.5.3 Safe Harbor
As at Holtwood, the FERC exercised a standard license article included in every
FERC license required Safe Harbor Water Power Corporation (and in proportion to
percent ownership, PPL) to design and install upstream fish passage facilities.
The Safe Harbor license also required PPL to study minimum flow need below the
project.
Some of the modifications to the Safe Harbor license were required because the
Commonwealth of Pennsylvania requested the project impoundment have limited
surface elevation fluctuation from mid-March to mid-September rather that the
mid-May to mid-September recreational use period. The state cited concerns with
fish spawning as a reason to limit the March to May fluctuations in elevation.
Safe Harbor prefers to allow a wider range of fluctuation to ensure a wider and
more reliable range of operating capacity in that season. In addition on October
28, 1998, the FERC modified the project license and approved the request from
Safe Harbor Water Power Corporation to raise the maximum pool elevation by 0.8
feet. Because of the license amendment, Safe Harbor and PPL have conducted
extensive fish, shorebird, and mudflat studies in the project impoundment. These
studies and reporting are currently scheduled to extend to February of 2003.
1.6.5.4 Maine Hydros
A detailed environmental review of the Maine hydroelectric units was not
performed. Based on discussions held with the manager of the Maine Hydro fleet,
a number of modifications have been made to the dam structures to accommodate
fish passage. The costs of some additional modifications are include the
Financial Projections.
1.7 International Distribution Companies
1.7.1 Description and Technical Characteristics
Stone & Webster performed an independent technical review of some key
distribution companies in PPL's portfolio. The distribution companies reviewed
were Emelectric, Emelari, Emelat, Eliqsa and Elecda in Chile, Elfec in Bolivia,
CEMAR in Brazil and DelSur in El Salvador. The PPL Global ownership of the first
6 companies is 61% and this is held directly or indirectly Emel's group. PPL
Global owns 84.7% of CEMAR and 80.5% of DelSur.
A-38
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Stone & Webster assessed the main characteristics, strengths, and weaknesses of
the distribution companies and the current operation and maintenance practices
as well as those planned to be implemented. This analysis also included a review
of growth potential, need of improvements and future capital requirements as
well as a review of the projections of operating costs and the formulation of
alternative scenarios. Stone & Webster also reviewed PPL Global Business Plan
for reasonableness of the projections and accuracy. During this review Stone &
Webster produced alternative scenarios to evaluate the effect of deviations from
PPL assumptions. For this review a tax model was provided by PPL and we are
providing no opinion in this respect.
In general, Stone & Webster finds that the systems in the reviewed companies are
in a reasonable good condition, its staff is knowledgeable and that the required
improvements can he implemented cost-effectively. The systems are in general
technically sound, though in most companies the level of investment seems to be
close to the minimum required to provide the service. This is particularly the
case in DelSur, which has one of the low level of investment per customer.
Therefore, as indicated in the body of this report, it is Stone & Webster's
opinion that the level of investment per customer in DelSur needs to increase,
to bring the companies in compliance with the more stringent quality of service
standards that the companies are likely to face.
Tables 6-1 and 6-2 below summarize the technical characteristics of the
distributions systems.
The distribution companies reviewed, Emelectric, Emelari, Emelat, Eliqsa and
Elecda in Chile, Elfec in Bolivia, CEMAR in Brazil and DelSur in El Salvador
were found to be in good to fair condition with experienced and knowledgeable
staff We also found that required improvements can he implemented
cost-effectively.
The systems are in general technically sound, though in most companies the level
of investment seems to be close to the minimum required to provide the level of
service. This is particularly the case in DelSur, which has a low level of
investment per customer. Therefore, as indicated in the body of this report, it
is Stone & Webster's opinion that the level of investment per customer in DelSur
needs to increase, to bring the companies in compliance with the more stringent
quality of service standards that the companies are likely to face.
A-39
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-8
Summary of Emel Companies
- ------------------------------------------------------------------------------------------------------------------------------------
Company EMELECTRIC ELECDA ELIQSA EMELARI EMELAT ELFEC
- ------------------------------------------------------------------------------------------------------------------------------------
Authorized Service 11,052 km2. 97 km2, 87 km2, 70 km2, Arica 7196 km2, 55,600 km2.,
Territory Region II in Region I in Desert, Region III in Department of
Regions VI, VII, and northern Chile northern Northern Chile northern Chile Cochabamba in
(km2) VIII and in small parts Chile central Bolivia
of region V
- ------------------------------------------------------------------------------------------------------------------------------------
Number of 163,885 111,306 56,407 50,200 66,267 208,544
Customers
- ------------------------------------------------------------------------------------------------------------------------------------
Customer per km- 32 268 128 193 43 78
line
- ------------------------------------------------------------------------------------------------------------------------------------
Energy Sales MWh 511,500 406,403 257,038 171,516 309,461 519,346
- ------------------------------------------------------------------------------------------------------------------------------------
Average 250 304 380 285 389 208
Consumption
kWh/Customer-
month
- ------------------------------------------------------------------------------------------------------------------------------------
Average Annual 4.80% 2.72% 3.87% 2.25% 2.00% 5.92%
Sales Growth (1995-
1999)
- ------------------------------------------------------------------------------------------------------------------------------------
Peak Demand (MW) 138(1) 87 60 43 70 115
- ------------------------------------------------------------------------------------------------------------------------------------
System Load Factor 46% 57% 54% 50% 60% 57%
- ------------------------------------------------------------------------------------------------------------------------------------
Power Factor Reportedly close to Reportedly Reportedly Reportedly Reportedly Reportedly close
0.90 close to 0.90 close to 0.90 close to 0.90 close to 0.90 to 0.90
- ------------------------------------------------------------------------------------------------------------------------------------
Cash from 15.7 11.3 6.1 3.9 6.3 10.6
Operations M$
(1999)
- ------------------------------------------------------------------------------------------------------------------------------------
System Voltages 13.2 - 13.8 kV, 23 kV 13.2 - 13.8 13.8 kV & 24 13.2 kV & 23 13.2 kV & 23 10 kV & 24.9 kV
and 66 kV kV, 4.l6 kV & kV kV kV
23kV
- ------------------------------------------------------------------------------------------------------------------------------------
Number of Poles 112,000 28,889 15,068 14,552 26,496
- ------------------------------------------------------------------------------------------------------------------------------------
(1) The 1999 demand includes Emetal, although for the calculation of the
growth this additional demand was not considered.
A-40
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-9
Summary of CEMAR and DelSur
- -------------------------------------------------------------------------------------------------------------------
Company CEMAR DELSUR
- -------------------------------------------------------------------------------------------------------------------
Authorized Service Territory 333,366 km2. 4,138 km2, Dept. of
Libertad, Cuscatlan and
(km2) State of Maranhao, Brazil San Salvador
- -------------------------------------------------------------------------------------------------------------------
Number of Customers 962,862 216,426
- -------------------------------------------------------------------------------------------------------------------
Customer per km-line 29 98
- -------------------------------------------------------------------------------------------------------------------
Energy Sales MWh 2,194,000 406,403
- -------------------------------------------------------------------------------------------------------------------
Average Consumption
kWh/Customer-month 190 295
- -------------------------------------------------------------------------------------------------------------------
Average Annual Sales Growth (1995-1999) 6.0% 6.9%
- -------------------------------------------------------------------------------------------------------------------
Peak Demand (MW) 503 145
- -------------------------------------------------------------------------------------------------------------------
System Load Factor 50% 60.3%
- -------------------------------------------------------------------------------------------------------------------
Power Factor Reportedly close to 0.85 Reportedly close to 0.90
and can be as low a 0.7
- -------------------------------------------------------------------------------------------------------------------
Cash from Operations M$ (1999) 18.3 16.3
- -------------------------------------------------------------------------------------------------------------------
System Voltages 138 kV, 69 kV, 34.5 kV and 23 - 24 kV, 13.2 - 13.8 kV
13.8 kV and 4.l6 kV
- -------------------------------------------------------------------------------------------------------------------
Number of Supply Substations 1 x 138/69/13.8 kV 3 x 44/4.16 kV
56x 69/13.8 kV 3 x 44/23 kV
lx 69/34.5 kV 13 x 44/13.2 kV
lx 69/34.5/13.8 kV 2 x 22/2.3 kV
17x 34.5 kV/13.8 kV
- -------------------------------------------------------------------------------------------------------------------
Km of high volt Feeders 4,483 2,201
- -------------------------------------------------------------------------------------------------------------------
1.7.2 Benchmark Analysis
In evaluating international distribution companies, Stone & Webster typically
assesses certain performance factors against benchmarks to evaluate the
projected performance of the distribution company. For Emel, CEMAR, and DelSur,
Stone & Webster used the following four performance factor:
o Customer per Employee
o O&M Cost per Customer
o Technical and Non-Technical Losses
o Gross Book Value per Customer
1.7.2.1 Customer per Employee
Figure 1-5 presents the customer per employee factors for the distribution
companies evaluated by Stone & Webster alongside values from comparable
companies.
A-41
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Figure 1-5
Customers per Employee
[GRAPH]
In Stone & Webster's opinion the level of staffing at Emel's companies is close
to the optimum levels and we see further increases in productivity to be
unlikely. Figure 1-5 shows the value of this index as projected by Emel in its
business plan. It should be noted that Stone & Webster's review questions the
validity of significant increases in productivity for one of the Emel companies,
Elfec.
One interesting aspect about Emel's personnel structure is the fairly large
component of administrative staff, which in some cases like Emelari can surpass
the operations and maintenance staff. This situation is mainly due to the large
level of outsourcing employed by the company. Furthermore, this high level of
outsourcing is one of the key reasons for the achievement of a high customer per
employee index.
In 1999, CEMAR, according to the information provided, had 2,096 workers and
962,826 customers. This implies that CEMAR had an employee to customer factor of
459, which is an acceptable value for a developing country. However, under the
new management, CEMAR expects to reduce the workforce by approximately 390
workers, thus increasing the factor to 590 customers per employee. CEMAR is also
projecting to increase this factor further to 680 worker per employee by 2010.
These goals are in theory achievable and well within what has been achieved in
other developing countries. However, this reduction will remain a challenge
given the location of the company and the low density of its load. In Stone &
Webster's opinion, the level of staffing at CEMAR can be improved, and CEMAR's
short term projections are achievable. The long-term projection is also
considered realistic but will require an effort to achieve.
Only limited information on DelSur was available for review by Stone & Webster.
In 1999 the number of customers per employee exceeded the 800 customers/employee
mark, which is one of the best indicators that we have seen in developing
countries. DelSur in its business plan is
A-42
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
further projecting that the number of customers per employee will increase from
803 in 1999 to 957 by 2001. This increase might prove to be overly optimistic,
but in any case, the operation at DelSur appears to be very efficient.
1.7.2.2 O&M Cost per Customer
Figure 1-6 presents the O&M costs per customer factors for the distribution
companies evaluated by Stone & Webster alongside values from comparable
companies. One aspect that complicates the comparison is that higher intensity
customers tend to demand higher quality of service and hence require a higher
cost to serve them.
Figure 1-6
Operation and Maintenance Cost per Customer
[GRAPH]
The O&M cost per customer for Emel's Chilean companies are slightly above the
expected value for developing countries ($75/customer) but below the typical
value for developed countries (US$1OO/customer) and values for companies like
LIGHT, Paulista and Electropaulo (Brazil), EMCALI (Colombia) and Peru (Luz del
Sur). All the representative companies that are below Emel's Chilean companies
are in countries with significant subsidies, like Turkey (Korfez and TEDAS) or
with weaker economies (EEGSA - Guatemala, Nicaragua and Panama). The O&M cost
per customer for Elfec, Emel's Bolivian company, is the general range of these
companies located in countries with weaker economies.
The O&M costs per customer for CEMAR are low. In 1999, this factor was US$58 per
customer, which is in the low end of the group. It is important to point out
that the companies that were below CEMAR, were also experiencing quality of
service problems, as is the case with this company. Based on the data shown in
Figure 1-6, it is Stone & Webster opinion that as CEMAR changes to be in
compliance with increasingly stricter quality of service requirements, the O&M
costs will increase despite the fact that the efficiency indicator of customer
per employee will also increase. CEMAR's management expects a jump this year as
they take over the operations and
A-43
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
start improvement programs. The future projections are in line with similar
companies and slightly above the benchmark for developing countries. Therefore,
it is Stone & Webster opinion that the O&M cost projections for CEMAR are
reasonable.
In 1999, DelSur had an O&M cost per customer of US$63, which is a very good
value as indicated in Figure 1-6. DelSur projects this value to remain
approximately constant in nominal terms (US$69/custumer in 2010), which is
reasonable given that efficiency gains at least at par with the inflation, are
typical.
1.7.2.3 Technical and Non-Technical Losses
Energy losses are categorized as "technical losses" such as those resulting from
the physical losses in cables, circuits, and transformers, and "non-technical
losses" such as those arising from billing errors, metering inaccuracies, and
theft of service. Control of both kinds of losses is of paramount importance for
distribution companies as they affect directly the bottom line. Figure 1-7
presents the loss factors for the distribution companies evaluated by Stone &
Webster alongside values from comparable companies.
Figure 1-7
Technical and Non-Technical Losses
[GRAPH]
Control of technical losses is a balance between investments in the system to
reduce them in the form of reactive compensation, larger caliber of wires and
transformation capacity, with the actual cost of these losses. Therefore
technical losses are always present, as there is always a minimum value under
which it is not economic to reduce them any further. Non-technical losses should
be reduced as much as practicable, and theoretically can reach a value of zero.
In practice there is always a small percentage of losses even in the best
companies.
Total losses in 1999 for the six Emel companies ranged between 5.5 and 8.5
percent. These loss levels are low as compared to other similar distribution
systems. The trend in technical and non-technical losses over the past five
years has been an improvement for Emelectric and Emelari,
A-44
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
and a slight decrease noted for Elecda, Eliqsa, and Emelat. One aspect that
helps Emel achieve these low loss levels is the large amount of energy sold and
delivered at high-voltage levels. High voltage energy sales range from 57% for
Emelectric and Emelat to 34% for Elecda. In general losses at these levels
suggest that current loss reduction programs are effective, and that the costs
for any additional efforts should be carefully weighed against potential
benefits. In the event the company loses high voltage clients to competition,
the law changes, or other circumstances affect the amount of energy delivered at
high voltage, Stone & Webster would expect the loss levels to increase.
There has been a gradual increase in the losses experienced by CEMAR over the
period 1994 to 1999. These loss levels are very high when compared with the
losses experienced by similar companies and represents and unacceptable
inefficiency. CEMAR should he able to achieve losses in the order of 10% or
lower. Based upon available information, it is estimated that technical losses
for CEMAR have been approximately l0.5% and non-technical losses have been
approximately 13.5% between 1996 and 1999. For a largely rural company like
CEMAR, the technical losses should be under 8%. Most of these losses are
associated with the distribution medium voltage (13.8 kV and 34.5 kV) and low
voltage network, because the losses at the transmission system (138 kV and 69
kV) have been in the 2.5% and 3% range over the years, which although a bit
high, are reasonable.
DelSur seems to be close to the point of minimum losses in a typical system,
however given the high cost of generation, it is economic for DelSur to reduce
the losses further. The losses in 1997 was 8.7%, which was reduced to 7.4% in
1999. The losses are projected to decrease to 6.3% in 2002, after which they are
assumed to have reached its minimum economic level.
1.7.2.4 Gross Book Value per Customer
Figure 1-8 presents the gross book value (GBV) per customer factors for the
distribution companies evaluated by Stone & Webster alongside values from
comparable companies. A typical value for developing countries is
US$1000/customer and US$2000/customer for developed countries.
A-45
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Figure 1-8
Gross Book Value per Customer
[GRAPH]
The relatively low value presented by Emel can be explained in terms of the
relatively low reliability indices and to a lesser degree the density of the
load (in customer per km-line). However, the drop forecast in the plan, in
nominal terms is optimistic. Stone & Webster believes that there will be
stronger reliability requirements in the future which would call for an increase
GBV per customer not a decrease. Even allowing for technology improvements, it
is our opinion the GBV per customer factor for Emel should be at least
US$500/custumer for the life of the plan.
Stone & Webster believes that CEMAR will need to significantly improve its
system to meet future quality of service requirements and therefore we would
expect to see a significant increase in the GBV for the company over the next
several years. CEMAR's capital expense projections result in an increase in the
GBV from a low of $439/customer to $523/customer in year 2000 and maintains a
level in the $550 to $590/customer range thereafter. These values, although low,
are deemed reasonable and are in the general low range of GBV in developing
countries.
DelSur has one of the lowest GBV per customer factors of the group and it is
projected to remain low. In fact only Guatemala had lower GBV and this country's
assets were in relatively poor shape and the reliability of the system was not
adequate. The reliability of DelSur needs to improve and we expect that the GBV
of this company will increase to be in the order of US$400 to US$500 per
customer.
1.8 Financial Projections
1.8.1 Overview
Stone & Webster has prepared Financial Projections for PPL from 2001 through
2020 showing cash available for debt service. Due to the diversity of the
portfolio of assets and companies that comprise PPL Energy Supply, the Financial
Projections are organized into groups of assets and
A-46
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
then are consolidated. Elements of PPL Energy Supply that were not reviewed by
Stone & Webster are not shown in the Financial Projections. The consolidated
Financial Projections have three major components -- Domestic Generation,
International Distribution, and PPL Overhead.
The Financial Projections consist of a base case and two sensitivity cases. The
consolidated projections for the base case are shown in summary form below and
in Exhibit I, and the consolidated projections for the two sensitivity cases are
shown in Exhibit II. In addition, the detailed summaries of the projections that
support the consolidated projections are included in Exhibit I for the base
case.
The Financial Projections show a full year in 2001. The 2001 cash flow is not
based on actual market prices or electricity generation. Actual performance in
2001 may differ significantly from that shown in the Financial Projections, as
events such as the fire and subsequent extended outage of Brunner Island Unit 3
are not reflected in the Financial Projections.
The Financial Projections are based on market energy and capacity price
forecasts, and facility specific electricity generation forecasts (collectively
the "market forecast") developed by ICF Consulting ("Market Consultant"). In
addition to the electricity generation and market revenues, the market forecasts
include fuel and emission allowance price forecasts. The market forecasts are
for the domestic generation assets only. For the international distribution
assets, Stone & Webster evaluated the energy sales for the regulated
distribution companies owned by PPL in Latin America.
There were a number of adjustments made to the market forecasts by Stone &
Webster. These adjustments are as follows:
o As the market forecast reports results in real dollars and the
Financial Projections are in nominal dollars, the results of the
market forecast were inflated from the base year of 1998 at an
annual rate of 2.5%.
o Average heat rates were developed by Stone & Webster and used to
calculate fuel usage rather than the full load heat rates used by
the Market Consultant.
o For the coal-fired plants in Pennsylvania, the initial coal prices
are based on the current contract prices and the spot prices
forecasted by the Market Consultant.
o The generation and energy revenues for Susquehanna were adjusted to
account for the two planned up-rates (15 MW/unit in 2001/2002 and 50
MW/unit in 2003/2004).
o The fuel expenses projected for Susquehanna, as projected by the
Market Consultant, were not used in the Financial Projections. PPPL
has contracts for uranium procurement and refinement and the
fabrication and installation of the nuclear fuel assemblies. The
fuel expense used in the Financial Projections was developed based
on the contract pricing.
o Only two of the existing combustion turbine locations were included
in the market forecasts. As the combustion turbine at both these
locations are not projected to operate to any significant extent,
Stone & Webster treated all the existing combustion turbines as
capacity units without any energy generation.
Stone & Webster combined the market forecast developed by the Market Consultant
with the O&M expense forecasts and contract energy sale projections developed by
Stone & Webster, and the debt service schedule provided by the bond Initial
Purchaser to develop the Financial
A-47
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Projections. These financial projections represent our best judgement of the
projected performance of PPL Energy Supply. A summary of the base case Financial
Projections is shown below for select years:
2001 2002 2003 2005 2010 2015 2020
---- ---- ---- ---- ---- ---- ----
Domestic Generation Assets
Total Net Generation 54,821,552 57,311,901 58,729,713 72,142,743 69,975,462 66,794,831 66,170,096
Total Operating Revenues 2,130,261 2,616,463 2,357,906 2,945,154 3,752,319 3,990,251 4,157,085
Total Operating Expenses 928,645 1,041,466 1,122,143 1,421,441 1,615,388 1,646,039 1,804,317
Non-Income Taxes ($000) 47,435 40,986 38,880 35,240 31,427 23,214 25,522
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 1,154,181 1,534,011 1,196,883 1,488,473 2,105,505 2,320,998 2,327,247
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 285,381 258,744 266,949 248,675 208,051 175,742 196,377
Lease Payments 36,127 74,826 122,779 164,152 165,425 163,054 124,833
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Available 832,673 1,200,441 807,155 1,075,646 1,732,029 1,982,202 2,006,036
- ------------------------------------------------------------------------------------------------------------------------------------
International Distribution Assets
Energy Sold (MWh) 4,233,714 4,559,276 5,039,637 5,885,931 8,312,263 9,866,708 11,163,274
Total Operating Revenues 353,552 375,955 430,751 540,382 821,695 971,903 1,099,619
Total Operating Expenses 266,364 274,470 313,759 392,222 575,595 680,647 770,090
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 87,189 101,485 116,993 148,159 246,100 291,256 329,530
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 1,500 6,134 7,722 6,876 14,624 19,151 21,667
Total Non-Operating and G&A 23,879 12,810 15,660 24,859 53,753 62,696 70,935
Expenses
Capital Expenditures ($000) 84,299 69,333 39,643 50,018 44,023 53,049 60,020
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Available (19,489) 25,476 69,412 80,159 162,948 194,662 220,242
- ------------------------------------------------------------------------------------------------------------------------------------
PPL Overhead Expenses
Non-Operating and G&A Expenses 155,797 168,046 173,314 183,586 207,711 235,005 265,887
- ------------------------------------------------------------------------------------------------------------------------------------
Total Cash Available 657,387 1,057,871 703,253 972,219 1,687,267 1,941,858 1,960,391
- ------------------------------------------------------------------------------------------------------------------------------------
Interest Expense 126,828 60,361 62,304 63,996 64,009 64,009 64,009
====================================================================================================================================
Debt Service Coverage Ratio 5.18 17.53 11.29 15.19 26.36 30.34 30.63
====================================================================================================================================
1.8.2 Domestic Generation Assets
Stone & Webster prepared Financial Projections for PPL's domestic generation
assets from 2001 through 2020. The Financial Projections consists of a base
case, the results of which are shown below for select years:
A-48
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
2001 2002 2003 2005 2010 2015 2020
---- ---- ---- ---- ---- ---- ----
Net Generation (MWh) 54,821,552 57,311,901 58,729,713 72,142,743 69,975,462 66,794,831 66,170,096
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 31,043,565 30,375,744 31,110,038 33,677,785 -- -- --
Other Contract Sales 3,485,801 3,303,729 3,283,033 -- -- -- --
Net Market Sales (Purchases) 10,302,908 12,786,216 13,655,215 27,230,138 60,873,047 57,791,487 57,166,753
Montana Market Sales 2,573,057 4,180,472 4,353,734 4,749,663 9,004,303 8,962,463 9,003,343
Montana Contract Sales 5,214,000 4,516,456 4,127,712 4,127,712 98,112 40,880 --
- ------------------------------------------------------------------------------------------------------------------------------------
Total Power Sales 52,619,331 55,162,617 56,529,732 69,785,298 69,975,462 66,794,831 66,170,096
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 296,276 475,004 359,057 501,835 1,099,219 1,186,001 1,200,172
Mechant Energy Sales 282,703 369,337 383,378 786,995 2,213,674 2,299,019 2,459,835
Contract Capacity Sales (Purchases) 54,000 63,000 66,600 -- -- -- --
Contract Energy Sales (Purchases) 1,131,869 1,201,237 1,157,977 1,266,291 (5,983) -- --
Montana Merchant Revenues 236,864 361,476 210,251 212,203 444,212 501,311 497,079
Montana Contract Revenues 101,985 121,241 156,748 155,882 (4,804) 921 --
Trading -- -- -- -- -- -- --
Other 26,565 25,169 23,896 21,949 6,000 3,000 --
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,130,261 2,616,463 2,357,906 2,945,154 3,752,319 3,990,251 4,157,085
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Fuel 481,883 565,385 608,528 848,182 969,264 922,972 951,583
O&M 401,515 431,989 470,252 531,335 619,321 692,841 818,639
Other Montana Operating Expenses 21,581 22,123 22,667 23,774 26,803 30,226 34,096
Nuclear Decommissioning Expense 23,666 21,969 20,696 18,149 -- -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 928,645 1,041,466 1,122,143 1,421,441 1,615,388 1,646,039 1,804,317
- ------------------------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 47,435 40,986 38,880 35,240 31,427 23,214 25,522
Operating Cash Flow ($000) 1,154,181 1,534,011 1,196,883 1,488,473 2,105,505 2,320,998 2,327,247
Capital Expenditures ($000)
Pennsylvania Fossil 106,197 98,067 86,395 94,225 106,142 55,176 62,427
Pennsylvania Hydro 4,826 959 937 3,677 1,190 1,346 1,523
Pennsylvania New Projects -- -- -- -- -- -- --
Pennsylvania Nuclear Projects 37,710 49,500 67,500 35,100 20,232 22,890 25,898
Pennsylvania Nuclear Fuel 55,803 55,306 54,788 57,562 65,126 73,684 83,367
Other New Projects 53,496 -- -- -- -- -- --
Montana 23,472 50,409 48,248 56,970 14,085 21,202 21,529
Maine 3,878 4,503 9,080 1,140 1,276 1,444 1,633
- ------------------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 285,381 258,744 266,949 248,675 208,051 175,742 196,377
- ------------------------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 36,127 48,338 46,110 37,490 40,501 39,783 3,134
Lease Payments for Lower Mt -- -- -- 35,464 33,726 32,073 30,501
Bethel
Lease Payments for New Units -- 26,488 76,669 91,198 91,198 91,198 91,198
($000)
====================================================================================================================================
Cash from Domestic Generation 832,673 1,200,441 807,155 1,075,646 1,732,029 1,982,202 2,006,036
Assets
====================================================================================================================================
A-49
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Shown in Table 1-10 are some key operating data and revenue information for
PPL's domestic electric generating facilities for 2001 through 2005 with average
data for various periods covered by the Financial Projections. The operating
data shown is the expected dispatch profile -- baseload, intermediate, and
peaking. The three modes of operation are defined as follows: baseload --
capacity factor of 60% to 100%; intermediate -- capacity factor of 20% to 60%;
and peaking -- capacity factor of 0% to 20%.
Also shown in the table is the expected revenue distribution between contract
and merchant energy and capacity revenues, as well as the number of operating
electric generating stations and units.
Table 1-10
Selected Operating Data
- ---------------------------------------------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 Average Average Average
2001-2005 2001-2010 2001-2020
- ---------------------------------------------------------------------------------------------------------------------------
Expected Dispatch Profile
- ---------------------------------------------------------------------------------------------------------------------------
% Baseload 99% 97% 94% 93% 94% 96% 95% 94%
- ---------------------------------------------------------------------------------------------------------------------------
% Intermediate 1% 1% 2% 3% 3% 2% 2% 2%
- ---------------------------------------------------------------------------------------------------------------------------
% Peaking 0% 2% 4% 4% 3% 3% 3% 4%
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Expected Revenue Distribution
- ---------------------------------------------------------------------------------------------------------------------------
% Contract 76% 69% 68% 63% 54% 66% 54% 26%
- ---------------------------------------------------------------------------------------------------------------------------
% Merchant 24% 31% 32% 37% 46% 34% 46% 74%
- ---------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------
Number of Stations 40 43 46 48 48 45 47 47
- ---------------------------------------------------------------------------------------------------------------------------
Number of Units 159 183 201 204 204 190 197 201
- ---------------------------------------------------------------------------------------------------------------------------
A description of the revenue and expense items shown in the Financial
Projections for the domestic generation assets are provided below.
1.8.2.1 Revenues
Revenues shown in the Financial Projections include both contract and merchant
capacity and energy revenues. The merchant revenues were determined by netting
the contract revenues from the revenues forecasted by the Market Consultant and
are shown for all the domestic generating assets except for the Montana plants.
For the Montana plants, the revenues are shown separately and include both
merchant and contract revenues. The Montana revenues were obtained from a
combination of the PPL Montana LLC Offering Memorandum, the forecasts prepared
by the Market Consultant, and revenues from the recently announced contract
between PPL and Montana Power.
In addition to the contract and merchant revenues from the sale of capacity and
energy, the Financial Projections include Other Revenues. Other Revenues are
related to certain fees passed through to PPL Energy Supply from PPL Electric
Utilities that are associated with the stranded cost settlement reached with
Pennsylvania and other revenues from the Montana facilities for items such as
headwaters benefits.
A-5O
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Contract Revenues
PLR Revenues
PPL's principal contract revenues are for sales to PPL Electric, followed by
revenues from the contract sales tied to the Montana assets. PPL has an all
requirements contract with PPL Electric to provide electric service for PPL
Electric's customers with Basic Utility Supply Service through 2001. PPL
Electric is the Provider of Last Resort (PLR) with the obligation to supply
Basic Utility Supply Service at the fixed rates established in the stranded cost
settlement with Pennsylvania through 2009. PPL participated in a competitive
bidding process for wholesale power sales to PPL Electric for the PLR sales for
2002 through 2009. PPL was selected to provide the power for the PLR load from
2002 through 2009. The bid submitted by PPL included an initial payment of $89
million, which represents the present value of the difference between the
projected market prices and the fixed rates for Basic Utility Supply Service.
This payment is included in the PLR revenues projected in 2002. As of the date
of this report, the wholesale power sales contract with PPL Electric has
received sonic regulatory approvals but has not been completely approved.
In addition to the PLR sales, PPL has wholesale power sales contracts with JCP&L
and a number of municipal power sales contracts. PPL also purchase power from
non-utility generators that had contracts with PPL Electric.
Stone & Webster received from the Market Consultant a projection for 20 years of
the generation and revenues from the domestic generating facilities. For
purposes of the Financial Projections, the contract sales and revenues were
netted from the energy and capacity sales and revenues forecasted by the Market
Consultant.
The price used to net the contract energy sales from the overall market energy
sales is assumed to be at a premium over the all hours average market price
projected by the Market Consultant to account for more sales during the peak
periods versus the off-peak periods. The average peak hours prices from 2001
through 2020 ranged from 15% to 12% above the average all hours price. To
determine the cost of supplying the energy for the contract obligations, the
purchase price was set at 108% of the average all hours price to weight the
price based on the load. The capacity price forecasted for PJM by the Market
Consultant was used to net the contract capacity sales and/or obligations from
the market capacity revenues.
The capacity obligation associated with the PLR sales in 2001, as forecasted by
PPL, is 5,563 MW in 2001. PPL's existing generation in Pennsylvania is in excess
of 8,300 MW so the capacity obligation can be met without the need to purchase
physical capacity. The energy supplied to meet the PLR contract has been
increased by 6% to compensate for transmission losses. The PLR revenues are
slightly less than the comparable market costs indicating that the PLR pricing
is below market.
The prices for PLR sales, without the gross receipt tax, are shown in Table 1-11
for residential, commercial, industrial and other customers. Within each
customer class, there are several subclasses, each with a separate price
schedule. The prices for each customer class are the load weighted average
prices from these sub-customer classes. Also shown in Table 1-11 are the
forecasted PLR sales and revenues.
The PLR sales forecast are a portion of PPL Electric's total retail sales. PPL
Electric's customers can choose different energy suppliers and the PLR sales
forecasts account for a total migration of sales in 2001 of 10.1%. The PLR sales
are projected to decrease by 2% in 2002, then increase by approximately 2% per
year through 2009. The anticipated customer migration from the
A-51
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
residential, industrial and other customer classes have been held constant
through 2009 at 99.0%, 86.3%, and 95.3%, respectively. The migration from the
commercial customer class, which has the highest prices, varies over the
contract period from a low of 73% in 2002 to a high of 97% in 2009.
Table 1-11
PLR Prices, Sales and Revenues in 2001
-------------------------------------------------------------------------------
Price ($/MWH) Sales (MWH) Revenues ($000)
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Residential 40.42 12,013,860 485,565
-------------------------------------------------------------------------------
Commercial 45.34 9,406,200 426,473
-------------------------------------------------------------------------------
Industrial 34.28 9,437,244 323,515
-------------------------------------------------------------------------------
Other 29.85 186,261 5,560
-------------------------------------------------------------------------------
Total 31,043,565 1,241,113
-------------------------------------------------------------------------------
Montana Contract Revenues
As part of the purchase of Montana Power's electric generating plants, PPL
agreed to supply power to Montana Power through June 30, 2002. These power sales
are part of two separate contracts between PPL and Montana Power (collectively
the Montana Transition Contracts). In addition, PPL assumed Montana Power's
contract with the Flathead Irrigation Project (FIP), which expires in 2015.
Recently, PPL announced it had negotiated a power sales agreement with Montana
Power that begins on July 1, 2002 and extends through June 30, 2007. This
contract has not been signed and Montana Power has recently indicated that it
will seek to renegotiate the price. The electricity sales, revenues and unit
prices for the contract sales to Montana are shown in Table 1-12.
A-52
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-12
Montana Contract Sales and Revenues
- -----------------------------------------------------------------------------------------------------------------------------------
Power Sales (MWh) Revenues ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
Transition New FIP Contract Total Transition New FIP Total Average
Contracts Contract Contracts Contract Contract Price
($/MWh)
- -----------------------------------------------------------------------------------------------------------------------------------
2001 5,115,888 84,000 5,199,888 113,829 1,433 115,262 22.17
- -----------------------------------------------------------------------------------------------------------------------------------
2002 2,403,544 2,014,800 84,000 4,502,344 53,479 80,592 1,461 135,532 30.10
- -----------------------------------------------------------------------------------------------------------------------------------
2003 4,029,600 84,000 4,113,600 161,184 1,490 162,674 39.55
- -----------------------------------------------------------------------------------------------------------------------------------
2004 4,029,600 84,000 4,113,600 161,184 1,520 162,704 39.55
- -----------------------------------------------------------------------------------------------------------------------------------
2005 4,029,600 84,000 4,113,600 161,184 1,551 162,735 39.56
- -----------------------------------------------------------------------------------------------------------------------------------
2006 4,029,600 84,000 4,113,600 161,184 1,582 162,766 39.57
- -----------------------------------------------------------------------------------------------------------------------------------
2007 2,014,800 84,000 2,098,800 80,592 1,614 82,206 39.17
- -----------------------------------------------------------------------------------------------------------------------------------
2008 84,000 84,000 1,647 1,647 19.61
- -----------------------------------------------------------------------------------------------------------------------------------
2009 84,000 84,000 1,681 1,681 20.01
- -----------------------------------------------------------------------------------------------------------------------------------
2010 84,000 84,000 1,716 1,716 20.43
- -----------------------------------------------------------------------------------------------------------------------------------
2011 84,000 84,000 1,751 1,751 20.85
- -----------------------------------------------------------------------------------------------------------------------------------
2012 84,000 84,000 1,788 1,788 21.29
- -----------------------------------------------------------------------------------------------------------------------------------
2013 84,000 84,000 1,825 1,825 21.73
- -----------------------------------------------------------------------------------------------------------------------------------
2014 84,000 84,000 1,863 1,863 22.18
- -----------------------------------------------------------------------------------------------------------------------------------
2015 41,000 41,000 921 921 22.46
- -----------------------------------------------------------------------------------------------------------------------------------
The contract revenues for the Montana Transition Contracts and the FIP contract
are based on our review of these contracts and data provided by PPL. The new
contract with Montana Power, as announced by PPL, is a unit contingent contract
for 500 MWh per hour of energy at a price of $40/MWh. After factoring in unit
outages, PPL estimates the average commitment to be 460 MWh per hour.
Other Contract Revenues
Other contract revenues include sales to wholesale and municipal customers and
the purchase of energy from non-utility generators (NUGs) under contract with
PPL Electric. PPL has wholesale contracts to supply energy and capacity to JCP&L
through May 2004. PPL has contracts with 18 municipalities for the supply of
energy. Three of the energy supply contracts expire at the end of January 2002.
The balance of the municipal supply contracts run through January 2004. The
wholesale and municipal contract sales and revenues are shown in Table 1-13.
As part of its restructuring settlement, PPL is to purchase the energy that PPL
Electric is obligated to purchase from Non-Utility Generators (NUGs). The
electricity projected to be purchased from the NUGs, as well as the cost of this
purchased power is shown in Table 1-14. The expense of purchasing the NUG is
based on the NUG contracts. As of January 1, 2001, PPL Electric will have eleven
outstanding NUG contracts. The contracts are through 2014 with most expiring
after 2009. The purchase of this energy is treated as a negative revenue and
offsets the market energy and capacity revenues received from the sale of the
NUGs energy and capacity.
A-53
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-13
Contract Energy and Capacity Sales and Revenues
----------------------------------------------------------------------------------------
JCP&L Energy JCP&L Energy JCP&L Municipal Municipal
Sales Revenues Capacity Sales Contract
Revenues Revenues
----------------------------------------------------------------------------------------
MWH $000 $001 MWH $000
----------------------------------------------------------------------------------------
2001 2,627,800 29,151 54,000 858,001 27,036
----------------------------------------------------------------------------------------
2002 2,627,800 28,921 63,000 675,929 22,702
----------------------------------------------------------------------------------------
2003 2,627,800 28,439 66,600 655,233 23,623
----------------------------------------------------------------------------------------
2004 1,094,400 11,844 30,900 62,254 1,969
----------------------------------------------------------------------------------------
Table 1-14
NUG Purchases and Expenses
-------------------------------------------------------------------------------
Purchases (MWH) Expense ($/MWh) Expense ($000)
-------------------------------------------------------------------------------
2001 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2002 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2003 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2004 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2005 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2006 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2007 2,537,187 65.20 165,431
-------------------------------------------------------------------------------
2008 1,772,806 64.93 115,105
-------------------------------------------------------------------------------
2009 1,268,608 64.64 82,008
-------------------------------------------------------------------------------
2010 95,335 62.75 5,983
-------------------------------------------------------------------------------
2011 40,364 59.98 2,421
-------------------------------------------------------------------------------
Other revenues shown in the Financial Projections are a capacity reservation
charge that compensates PPL for the decommissioning costs of the Susquehanna
units. A duplicate expense is shown in the Financial Projections.
Summary of Non-Montana Contract Revenues
A summary of the contract capacity and energy sales and revenues is presented in
Table 1-15 for all the non-Montana contracts. Both contract capacity sales and
obligations are shown in the table, but the revenues shown are only associated
with the wholesale power sales contracts. The capacity revenues, on a $/kW-yr
basis, are high, but are offset by low energy revenues ($1l/MWh) associated with
these contracts. Capacity obligations represent the capacity required to serve
the various contract loads. Capacity obligations are not priced but are built
into the contract energy prices. NUG capacity is the capacity associated with
the power being purchased under the NUG contracts.
Contract energy sales are shown to meet PPL Electric's PLR loads, PPL's
wholesale and municipal contract sales (shown as Other Contract Sales in Table
1-15), transmission losses associated with the contract sales, and purchases
from NUGs. The revenues from energy sales are shown both in total dollars and in
$/MWh. With the exception of the wholesale power sales contracts, the energy
sales revenues incorporate the capacity obligations associated with the power
sales contracts. For 2010 through 2014, the revenues, on a $/MWh basis, are for
the purchase of power from the non-utility generators.
A-54
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-15
Summary of Contract Sales and Revenues
Contract Capacity Sales/Obligations and Revenues
- --------------------------------------------------------------------------------------------------------------------------------
PLR Obligation Wholesale Municipal NUG Total Contract Revenues Revenues
(MW) Sales (MW) Obligation Obligations (MW) ($000) ($/kW-yr)
(MW) (MW)
- --------------------------------------------------------------------------------------------------------------------------------
2001 5,563 300 152 (322) 5,693 54,000 180
- --------------------------------------------------------------------------------------------------------------------------------
2002 5,758 300 120 (322) 5,855 63,000 210
- --------------------------------------------------------------------------------------------------------------------------------
2003 5,899 300 116 (322) 5,993 66,600 222
- --------------------------------------------------------------------------------------------------------------------------------
2004 6,110 125 11 (322) 5,924 30,900 247
- --------------------------------------------------------------------------------------------------------------------------------
2005 6,392 (322) 6,070
- --------------------------------------------------------------------------------------------------------------------------------
2006 6,533 (322) 6,211
- --------------------------------------------------------------------------------------------------------------------------------
2007 6,673 (322) 6,351
- --------------------------------------------------------------------------------------------------------------------------------
2008 6,808 (225) 6,584
- --------------------------------------------------------------------------------------------------------------------------------
2009 6,947 (161) 6,786
- --------------------------------------------------------------------------------------------------------------------------------
2010 (12) (12)
- --------------------------------------------------------------------------------------------------------------------------------
2011 (5) (5)
- --------------------------------------------------------------------------------------------------------------------------------
2012 (5) (5)
- --------------------------------------------------------------------------------------------------------------------------------
2013 (5) (5)
- --------------------------------------------------------------------------------------------------------------------------------
2014 (5) (5)
- --------------------------------------------------------------------------------------------------------------------------------
Contract Energy Sales and Revenues
- --------------------------------------------------------------------------------------------------------------------------------
PLR Sales Other Contract Transmission NUG Sales Total Sales Revenues Revenues
(MWh) Sales (MWh) Losses (MWh) (MWh) (MWh) ($000) ($/MWh)
- --------------------------------------------------------------------------------------------------------------------------------
2001 31,043,565 3,485,801 2,202,222 (2,537,187) 34,194,401 1,131,869 33.10
- --------------------------------------------------------------------------------------------------------------------------------
2002 30,375,744 3,303,729 2,149,284 (2,537,187) 33,291,570 1,201,237 36.08
- --------------------------------------------------------------------------------------------------------------------------------
2003 31,110,038 3,283,033 2,199,981 (2,537,187) 34,055,864 1,157,977 34.00
- --------------------------------------------------------------------------------------------------------------------------------
2004 32,206,476 1,156,654 2,256,570 (2,537,187) 33,082,513 1,185,828 35.84
- --------------------------------------------------------------------------------------------------------------------------------
2005 33,677,785 2,357,445 (2,537,187) 33,498,043 1,266,291 37.80
- --------------------------------------------------------------------------------------------------------------------------------
2006 34,404,881 2,408,342 (2,537,187) 34,276,036 1,422,137 41.49
- --------------------------------------------------------------------------------------------------------------------------------
2007 35,125,621 2,458,793 (2,537,187) 35,047,227 1,476,390 42.13
- --------------------------------------------------------------------------------------------------------------------------------
2008 35,826,477 2,507,853 (1,772,806) 36,561,524 1,588,850 43.46
- --------------------------------------------------------------------------------------------------------------------------------
2009 36,539,915 2,557,794 (1,268,608) 37,829,101 1,696,265 44.84
- --------------------------------------------------------------------------------------------------------------------------------
2010 (95,335) (95,335) (5,983) (62.75)
- --------------------------------------------------------------------------------------------------------------------------------
2011 (40,364) (40,364) (2,421) (59.98)
- --------------------------------------------------------------------------------------------------------------------------------
2012 (40,364) (40,364) (2,421) (59.98)
- --------------------------------------------------------------------------------------------------------------------------------
2013 (40,364) (40,364) (2,421) (59.98)
- --------------------------------------------------------------------------------------------------------------------------------
2014 (39,258) (39,258) (2,355) (59.98)
- --------------------------------------------------------------------------------------------------------------------------------
Merchant Revenues
The capacity and energy revenues forecasted by the Market Consultant were used
to establish the merchant revenues for all except the PPL Montana assets. For
PPL Montana, the energy and capacity revenues were obtained from the PPL Montana
Offering Memorandum.
A-55
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The energy and capacity revenues forecasted by the Market Consultant are shown
in Table 1-16, along with the available capacity and energy. The capacity price
shown is the weighted average price for the capacity in PJM, NEPOOL, NYPOOL,
Arizona, Washington, ComEd, and Montana regions. The increase in capacity from
2001 to 2005 is due to new units coming on-line and the uprate of the two
Susquehanna units. The energy price is the weighted average price for all the
units.
Table 1-16
Capacity and Energy Revenues Forecasted by Market Consultant
- -----------------------------------------------------------------------------------------------------------------------------------
Capacity (MW) Energy (MWh) Capacity Energy Revenues Capacity Energy
Revenues ($000) ($000) Revenues Revenues
($/kW-yr) ($/MWh)
- -----------------------------------------------------------------------------------------------------------------------------------
2001 9,035 54,800,702 1,095,795 1,962,114 121.28 35.80
- -----------------------------------------------------------------------------------------------------------------------------------
2002 10,649 57,296,549 1,576,094 1,851,219 148.01 32.31
- -----------------------------------------------------------------------------------------------------------------------------------
2003 11,216 58,649,221 857,431 1,775,168 76.45 30.27
- -----------------------------------------------------------------------------------------------------------------------------------
2004 11,856 61,273,046 890,414 1,828,358 75.10 29.84
- -----------------------------------------------------------------------------------------------------------------------------------
2005 13,073 71,599,794 1,082,086 2,141,735 82.77 29.91
- -----------------------------------------------------------------------------------------------------------------------------------
2006 13,073 71,480,549 1,110,290 2,223,530 84.93 31.11
- -----------------------------------------------------------------------------------------------------------------------------------
2007 13,073 71,380,866 1,139,390 2,309,339 87.16 32.35
- -----------------------------------------------------------------------------------------------------------------------------------
2008 13,073 70,980,819 1,161,503 2,395,802 88.85 33.75
- -----------------------------------------------------------------------------------------------------------------------------------
2009 13,079 70,454,628 1,187,450 2,474,395 90.79 35.12
- -----------------------------------------------------------------------------------------------------------------------------------
2010 13,079 69,194,711 1,205,071 2,529,543 92.14 36.56
- -----------------------------------------------------------------------------------------------------------------------------------
2011 13,079 68,403,688 1,226,229 2,545,214 93.76 37.21
- -----------------------------------------------------------------------------------------------------------------------------------
2012 13,079 67,829,944 1,250,860 2,568,395 95.64 37.87
- -----------------------------------------------------------------------------------------------------------------------------------
2013 13,079 66,876,199 1,276,277 2,570,310 97.58 38.43
- -----------------------------------------------------------------------------------------------------------------------------------
2014 13,079 66,430,520 1,302,506 2,598,151 99.59 39.11
- -----------------------------------------------------------------------------------------------------------------------------------
2015 12,993 65,486,991 1,319,345 2,600,951 101.54 39.72
- -----------------------------------------------------------------------------------------------------------------------------------
2016 12,909 64,821,324 1,325,955 2,601,765 102.72 40.14
- -----------------------------------------------------------------------------------------------------------------------------------
2017 12,909 64,683,690 1,342,135 2,629,687 103.97 40.65
- -----------------------------------------------------------------------------------------------------------------------------------
2018 12,909 64,558,982 1,358,523 2,658,883 105.24 41.19
- -----------------------------------------------------------------------------------------------------------------------------------
2019 12,909 64,446,961 1,375,121 2,689,378 106.52 41.73
- -----------------------------------------------------------------------------------------------------------------------------------
2020 12,900 64,292,267 1,331,706 2,718,486 103.23 42.28
- -----------------------------------------------------------------------------------------------------------------------------------
The merchant capacity and energy revenues include an estimate of the capacity
and energy revenues that PPL derives from the sale of power from the non-utility
generators (NUGs) whose power sales contracts have been transferred from PPL
Electric to PPL Energy Supply. The energy price for the sale of the power from
the NUGs is assumed to be the average all hours energy price forecasted by the
Market Consultant. The capacity price used to determine the capacity revenues
from the NUG power sales to the market is the market capacity price forecasted
by the Market Consultant. The merchant capacity and energy sales and revenues
are shown in Table 1-17 for 2001 through 2015. After 2015, there are no
projected contract sales so the merchant revenues are the same as those
forecasted by the Market Consultant. Generally, the realized price for the
merchant revenues is slightly below the price forecasted by the Market
Consultant as the contract pricing has been below the market prices.
A-56
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-17
Merchant Capacity and Energy Revenues
- -----------------------------------------------------------------------------------------------------------------------------
Total Capacity Contract Capacity Merchant Capacity Merchant Capacity Merchant Capacity
(MW) Sales/Obligations (MW) Revenues ($000) Revenues
(MW) ($/kW-yr)
- -----------------------------------------------------------------------------------------------------------------------------
2001 9,035 6,397 2,638 371,399 140.77
- -----------------------------------------------------------------------------------------------------------------------------
2002 10,649 6,452 4,197 633,828 151.03
- -----------------------------------------------------------------------------------------------------------------------------
2003 11,216 6,505 4,711 413,265 87.72
- -----------------------------------------------------------------------------------------------------------------------------
2004 11,856 6,436 5,420 421,685 77.80
- -----------------------------------------------------------------------------------------------------------------------------
2005 13,073 6,581 6,491 558,120 85.98
- -----------------------------------------------------------------------------------------------------------------------------
2006 13,073 6,722 6,351 563,555 88.73
- -----------------------------------------------------------------------------------------------------------------------------
2007 13,073 6,613 6,460 587,292 90.91
- -----------------------------------------------------------------------------------------------------------------------------
2008 13,073 6,595 6,478 604,881 93.37
- -----------------------------------------------------------------------------------------------------------------------------
2009 13,079 6,798 6,281 607,094 96.65
- -----------------------------------------------------------------------------------------------------------------------------
2010 13,079 (1) 13,080 1,204,176 92.06
- -----------------------------------------------------------------------------------------------------------------------------
2011 13,079 6 13,073 1,225,272 93.73
- -----------------------------------------------------------------------------------------------------------------------------
2012 13,079 6 13,073 1,249,838 95.61
- -----------------------------------------------------------------------------------------------------------------------------
2013 13,079 6 13,073 1,275,184 97.54
- -----------------------------------------------------------------------------------------------------------------------------
2014 13,079 6 13,073 1,301,337 99.55
- -----------------------------------------------------------------------------------------------------------------------------
2015 12,993 5 12,988 1,318,825 101.54
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
Total Energy Contract Energy Merchant Energy Merchant Energy Merchant Energy
(MWh) Sales (MWh) Sales (MWh) Revenues ($000) Revenues ($/MWh)
- -----------------------------------------------------------------------------------------------------------------------------
2001 54,800,702 39,394,289 15,406,413 452,536 29.37
- -----------------------------------------------------------------------------------------------------------------------------
2002 57,296,549 37,793,914 19,502,635 583,874 29.94
- -----------------------------------------------------------------------------------------------------------------------------
2003 58,649,221 38,169,464 20,479,756 538,852 26.31
- -----------------------------------------------------------------------------------------------------------------------------
2004 61,273,046 37,196,113 24,076,933 622,389 25.85
- -----------------------------------------------------------------------------------------------------------------------------
2005 71,599,794 37,611,643 33,988,152 917,915 27.01
- -----------------------------------------------------------------------------------------------------------------------------
2006 71,480,549 38,389,636 33,090,913 921,950 27.86
- -----------------------------------------------------------------------------------------------------------------------------
2007 71,380,866 37,146,027 34,234,839 989,311 28.90
- -----------------------------------------------------------------------------------------------------------------------------
2008 70,980,819 36,645,524 34,335,295 1,057,714 30.81
- -----------------------------------------------------------------------------------------------------------------------------
2009 70,454,628 37,913,101 32,541,527 1,049,413 32.25
- -----------------------------------------------------------------------------------------------------------------------------
2010 69,194,711 (11,335) 69,206,046 2,526,428 36.51
- -----------------------------------------------------------------------------------------------------------------------------
2011 68,403,688 43,636 68,360,052 2,542,104 37.19
- -----------------------------------------------------------------------------------------------------------------------------
2012 67,829,944 43,636 67,786,308 2,565,289 37.84
- -----------------------------------------------------------------------------------------------------------------------------
2013 66,876,199 43,636 66,832,563 2,567,209 38.41
- -----------------------------------------------------------------------------------------------------------------------------
2014 66,430,520 44,742 66,385,779 2,595,054 39.09
- -----------------------------------------------------------------------------------------------------------------------------
2015 65,486,991 41,000 65,445,991 2,599,662 39.72
- -----------------------------------------------------------------------------------------------------------------------------
A-57
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Other Revenues
Other revenues are the Competitive Transition Charges (CTC) recovered from the
ratebase to support the nuclear decommissioning fund for the Susquehanna units,
other nuclear related costs, and headwaters benefits revenues from the Montana
hydroelectric plants. The other revenues start at approximately $27 million in
2001 and decline to $19 million in 2009, after which nuclear expense recovery
stops. The headwaters benefits revenues continue into 2015.
1.8.2.2 Operating Expenses
Operating expenses for the domestic electric generating units shown in the
Financial Projections include fuel, operation and maintenance charges for Assets
reviewed by Stone & Webster, operation expenses for the PPL Montana plants, and
payments to the nuclear decommissioning fund for the Susquehanna units. The
nuclear decommissioning fund payments match the other revenues.
Fuel Expenses
Fuel expenses include the costs of fossil fuel supply and transportation, the
cost of managing the fossil fuel procurement and transportation, the purchase
cost and/or the revenues from the sale of additional emission allowances.
The primary fuel for the existing fossil fuel-fired generating assets is coal.
All the units burn coal, except for Martins Creek Units 3 and 4, Wyman Unit 4,
and the existing combustion turbines. As most of the fuel burned is coal, the
primary fuel expense is for the purchase and transportation of coal. PPL
contracts for most of its coal supply through multi-year contracts. All coal is
delivered by rail. PPL has transportation agreements with CSX Transportation,
Inc. and with Norfolk Southern Railway Company. These transportation agreements
are in effect through October 1, 2003 and September 1, 2007, respectively. Coal
is transported in coal cars owned or leased by PPL. The existing contracted coal
suppliers are listed below with the term of the contract:
o AEI Coal Sales Co., Inc. - through December 2003
o Anker Energy Corp. - through Dec. 2001
o Amvest Coal Sales, Inc. (Nicholas-Clay Co., LLC) - through Dec. 2002
o Arch Coal Sales Co., Inc. - through Dec. 2000
o Coastal Coal - West Virginia, LLC - through Dec. 2002
o Consol Pennsylvania Coal - through Dec. 2003
o Smoky Mountain Coal Corp - through 2001
o E.P. Bender Coal Co., Inc. - through Dec. 2004
o K&J Coal Co., Inc. - through 2004
o Logan & Kanawha Coal Co., Inc. - through Dec. 2001
o RAG Emerald Resources Corp. - through 2002
o RAG Coal Sales of America - through 2002
o Solid Fuel LLC - through 2007 (synfuel)
A-58
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Shown in Table 1-18 is the percentage of coal purchased under contract and on
the spot market for each station. Coal for Montour, Brunner Island and Martins
Creek comes from three areas - Central Pennsylvania ("Central PA"), Southwestern
Pennsylvania ("SW PA"), and Central Appalachia ("Central AP"). Montour burns a
combination of Central PA and SW PA coals. Brunner Island burns primarily
Central AP coal. As the coal supply requirements for the two units at Martins
Creek are substantially lower than that for Brunner Island and Montour, the
source of the coal burned at Martins Creek is projected to be more variable. The
coal burned at Conemaugh and Keystone are from Central PA and SW PA mines.
PPL's coal contracting strategy has been to enter into four year contracts with
multiple suppliers and have these contracted staggered in time so that there are
always some contracts expiring each year with a comparable number of contracts
being entered into. Coal prices in the east have increased significantly in the
past year, with price increases being as much as 500%. This run up in coal
prices is not expected to be a long-term increase. Rather than lock in these
high prices in its contracts, PPL has deferred entering into new coal supply
contracts, which is increasing its risk to spot prices in 2003 and 2004. The
coal prices, as projected by the Market Consultant, are projected to decrease in
2002 through 2005, remain constant in real terms from 2005 through 2010, then
decrease in real terms for 2011 through 2020. The average price shown in Table
2-30 is based on the contract prices and the spot prices forecasted by the
Market Consultant.
The coal from each region has certain general characteristics. Central PA coal
tends to be softer than the other coals and has a higher sulfur content (~1.7 lb
sulfur/MMBtu). SW PA coal has a medium hardness and a sulfur content of
approximately 1.0 lb sulfur/MMBtu. SW PA coal also tends to have a higher
volatile content than the other coals. Higher volatile coal produces lower NO(x)
emissions and is used by some plants predominantly during the ozone season.
Central AP coal tends to be harder and have a low sulfur content (~0.6 lb
sulfur/MMBtu).
Table 2-30 also shows the average heat and sulfur contents burned at each
station, as well as the average delivered price. Compared to the coal burned at
Brunner Island, the coals burned at Montour have a higher sulfur content and a
lower price. Higher sulfur coals tend to be cheaper than lower sulfur coals. In
addition, the transportation costs are lower for Central PA and SW PA coals
delivered to Montour than Central AP coals delivered to Brunner Island. The coal
burned by Conemaugh and Keystone is similar to that burned at Montour; however,
the Conemaugh and Keystone Stations are located closer to both the Central PA
and SW PA mines and therefore benefits from lower transportation costs.
Both PPL and the operators of the Conemaugh and Keystone Stations have
negotiated with various parties to burn a synfuel as a means of reducing the
fuel costs. It is possible to earn significant tax credits by building and
operating synfuel facilities under existing Federal laws. The approach being
pursued by PPL and the Conemaugh and Keystone operators is to have a synfuel
facility to be constructed at the stations. The synfuel plant would process the
coal delivered to the station by adding a binder material that represents 1% to
2% of the weight of the coal. Adding the binder material changes the coal enough
for it to be considered a synfuel. Various synfuels have been tested at a number
of units with no noticeable operational impact. Agreements have been reached for
the construction of synfuel facilities at Brunner Island, Montour, and Keystone.
The Brunner Island synfuel facility went into operation in June 2001. The
Montour synfuel facility is expected to go into operation in August/September
2001. Discussions are ongoing concerning the construction of a synfuel facility
at Conemaugh Station. The synfuel developer would be responsible for the
construction and operation of the plants and can claim the associated tax
credits, part of which is passed through to the stations as a reduction in the
fuel cost. The anticipated savings associated with burning synfuels is
approximately 10%
A-59
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
of the delivered fuel cost. The current Federal law allows the synfuels tax
credit to be claimed through 2007.
Table 1-18
Coal Contracting Strategy, Characteristics and Prices
- ---------------------------------------------------------------------------------------------------------
2001 2002 2003 2004
- ---------------------------------------------------------------------------------------------------------
Brunner Island
- ---------------------------------------------------------------------------------------------------------
% Contracted 64% 68% 72% 6%
- ---------------------------------------------------------------------------------------------------------
% Spot 36% 32% 78% 94%
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Average Heat Content Btu/lb 12,554 12,607 12,508 12,494
- ---------------------------------------------------------------------------------------------------------
Average Sulfur Content lb S/MMBtu 0.70 0.71 0.66 0.61
- ---------------------------------------------------------------------------------------------------------
Average Price $/MMBtu 1.582 1.723 1.600 1.557
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Montour
- ---------------------------------------------------------------------------------------------------------
% Contracted 66% 46% 3% 3%
- ---------------------------------------------------------------------------------------------------------
% Spot 34 54% 97% 97%
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Average Heat Content Btu/lb 12,738 12,707 12,500 12,500
- ---------------------------------------------------------------------------------------------------------
Average Sulfur Content lb S/MMBtu 1.31 1.44 1.68 1.68
- ---------------------------------------------------------------------------------------------------------
Average Price $/MMBtu 1.431 1.610 1.613 1.561
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Martins Creek
- ---------------------------------------------------------------------------------------------------------
% Contracted 62% 37% 19% 17%
- ---------------------------------------------------------------------------------------------------------
% Spot 38% 63% 81% 83%
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Average Heat Content Btu/lb 12,645 12,537 12,500 12,500
- ---------------------------------------------------------------------------------------------------------
Average Sulfur Content lb S/MMBtu 0.88 0.85 0.93 0.93
- ---------------------------------------------------------------------------------------------------------
Average Price $/MMBtu 1.489 1.648 1.644 1.599
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Conemaugh
- ---------------------------------------------------------------------------------------------------------
% Contracted 83% 70% 83% 83%
- ---------------------------------------------------------------------------------------------------------
% Spot 17% 30% 17% 17%
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Average Heat Content Btu/lb 12,650 12,600 12,650 12,650
- ---------------------------------------------------------------------------------------------------------
Average Sulfur Content lb S/MMBtu 1.85 1.85 1.85 1.85
- ---------------------------------------------------------------------------------------------------------
Average Price $/MMBtu 1.080 1.215 1.217 1.178
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Keystone
- ---------------------------------------------------------------------------------------------------------
% Contracted 70% 96% 71% 71%
- ---------------------------------------------------------------------------------------------------------
% Spot 30% 4% 29% 29%
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Average Heat Content Btu/lb 1.75 1.75 1.75 1.75
- ---------------------------------------------------------------------------------------------------------
Average Sulfur Content lb S/MMBtu 12,650 12,750 12,750 12,800
- ---------------------------------------------------------------------------------------------------------
Average Price $/MMBtu 1.090 1.227 1.229 1.189
- ---------------------------------------------------------------------------------------------------------
There are some additional operating costs associated with the operation of the
synfuel facilities. These operating costs are typically related to increased
on-site fuel handling expenses. The increased operating costs are likely to be a
fraction of the savings that are realized from using the
A-60
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
synfuel. The potential savings associated with the synfuels program and the
potential costs have not been factored into the Financial Projections.
The delivered coal prices shown in Table 1-18 for the wholly-owned facilities
does not include the cost of maintaining PPL-owned coal cars and leasing
additional coal cars. The cost of maintaining and leasing coal cars is shown as
separate expense. This expense is based on historical and budgeted costs for
maintaining and leasing cars and is projected to be $13.5 million in 2001.
The coal prices in the first four years of the Financial Projections (2001
through 2004) for the wholly-owned plants are based on the existing coal
contracts and the Market Consultant's projection of spot coal prices. After
2004, the coal price is the spot price forecasted by the Market Consultant. The
coal prices for Conemaugh and Keystone for 2001 were obtained from the fuel
plans prepared by the Conemaugh and Keystone operators. For Conemaugh and
Keystone, the coal price for 2002 on is the spot price forecasted by the Market
Consultant.
The coal prices for the Montana fossil-fired units are from the Market
Consultant's projections and appear to be consistent with information reported
on the coal contracts for Colstrip and Corette Stations.
The unit dispatch projections prepared the Market Consultant shows Martins Creek
Units 3 and 4 being dispatched at a very low level over the next 20 years (less
than 1% capacity factor); hence, there are only minor expenses shown for oil and
gas purchases. Stone & Webster is not aware of any firm supply or transportation
contracts for Martins Creek Unit 3 and 4. The combustion turbines all burn
distillate oil. As it is assumed that the combustion turbines do not generate
electricity during the 20 years of the Financial Projections, no fuel expenses
are shown for these units. Similarly, Wyman Unit 4 is only shown to be
dispatched in 2001, and then only at a low capacity factor. Consequently, the
fuel expense for Wyman Unit 4 is also minimal.
Existing Fossil-Fuel Fired Units -- Emission Allowance Costs/Revenues
The cost/revenue from the purchase/sale of SO(2) and NO(x) emission allowances
is shown in the Financial Projections as part of the fuel expense. The emission
allowance prices used to calculate the cost/revenue related to the emission
allowances in the Financial Projections were provided by the Market Consultant
and are shown in Table 1-19.
A-61
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-19
Emission Allowance Prices and Expenses (Revenues)
- --------------------------------------------------------------------------------------------------------------------------------
Year SO(2) Allowance SO(2) Expense Purchased or NO(x) Allowance NO(x) Expense Purchased or
Prices (Revenue)(1) Sold Allowances Prices (Revenue) Sold Allowances
as a % of as a % of
($/ton) ($000s) Uncontrolled SO(2) ($/ton) ($000s) Uncontrolled NO(x)
Emissions Emissions
- --------------------------------------------------------------------------------------------------------------------------------
2001 220 -- 0% 1,022 (8,646) -28%
- --------------------------------------------------------------------------------------------------------------------------------
2002 233 -- 0% 505 (4,199) -27%
- --------------------------------------------------------------------------------------------------------------------------------
2003 246 -- 0% 3,210 736 1%
- --------------------------------------------------------------------------------------------------------------------------------
2005 297 4,366 10% 2,261 (3,912) -6%
- --------------------------------------------------------------------------------------------------------------------------------
2007 356 34,738 69% 2,715 (5,005) -6%
- --------------------------------------------------------------------------------------------------------------------------------
2010 469 (12,065) -17% 3,570 (4,300) -4%
- --------------------------------------------------------------------------------------------------------------------------------
2015 874 (41,446) -33% 5,382 (22,438) -15%
- --------------------------------------------------------------------------------------------------------------------------------
2020 989 (42,866) -30% 6,089 (25,824) -15%
- --------------------------------------------------------------------------------------------------------------------------------
(1) Banked SO(2) allowances used to supply additional SO(2) allowances
required through part of 2005.
In the initial years of the Financial Projections, the cost/revenue for SO(2)
emission allowances is $O. PPL has purchased additional SO(2) allowances and has
banked these allowances for future use. It is assumed that this bank of
allowances will be drawn upon in the initial years of the Financial Projections
so there is no cost for purchasing required SO(2) allowances. The banked
allowances are drawn down partway through 2005 and PPL will be required to
purchase additional SO(2) allowances until 2010 when it is assumed that the
scrubbers at Montour will be placed in service. The start of operation of
scrubbers at Montour is assumed to be 2010. No official decision has been made
by PPL to install scrubbers at Montour. The installation of scrubbers at Montour
was presented by PPL to Stone & Webster as a likely potential. A number of
factors will influence the final decision to install scrubbers and the timing of
the decision, including the cost of allowances and future environmental
regulations. Prior to the scrubbers coming on-line, PPL will be required to
obtain allowances equal to 10% to 69% of the total uncontrolled SO(2) emissions.
After the scrubbers are in operation, PPL will be generating excess SO(2)
allowances equal to 17% to 33% of the total uncontrolled SO(2) emissions.
With the two SCR systems installed at Montour, PPL will be generating excess
NO(x) allowances in 2001 and 2002. In 2003, the NO(x) allowances decline and PPL
will need to purchase additional NO(x) allowances. The total exposure is
limited, however, as the additional NO(x) allowances represent only 1% of the
total uncontrolled NO(x) emissions. The need to purchase NO(x) allowances is
short-lived as excess allowances are generated when the SCR system for Brunner
Island Unit 3 is placed in service in 2005. PPL generates excess NO(x)
allowances from 2005 through 2020. As with the scrubbers at Montour, PPL has not
officially committed to the installation of an SCR system in Brunner Island Unit
3. Nevertheless, the installation of an SCR system or SNCR systems at one or
more units at Brunner Island is considered likely by PPL.
New Development Units - Fuel Expenses
The fuel expenses for the Arizona, Connecticut, New York and Pennsylvania
natural gas-fired generating assets are based on the output from the Market
Consultant's study. Specifically, Stone & Webster used the net generation
forecasted by the Market Consultant for each unit and applied an average heat
rate to obtain the fuel usage. The total delivered fuel price forecasted by the
Market Consultant was applied to the fuel usage to obtain the fuel expense. The
fuel expense for select years is shown in Table 1-20 along with the delivered
fuel price.
A-62
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The fuel consumed by the new projects is natural gas. The Market Consultant's
total delivered fuel price were provided in 1998 dollars and have been converted
to nominal dollars based on an assumed annual inflation rate of 1.5% in 1999
and 2.5% thereafter.
Nuclear Units - Fuel Expenses
The expensed fuel charges consist of payments to the U.S. Department of Energy
("DOE") for waste disposal charges that are a function of the electricity
generation from the Susquehanna Station. For every MWh generated, net of
in-plant use, PPL's is charged $1/MWH as adjusted for transmission losses
($0.94/MWh). Additional payments are made to the DOE under the Energy Policy
Act. These payments are for decontamination and decommissioning ("D&D") costs.
As part of its restructuring, PPL is collecting these payments through the
Competitive Transition Charge ("CTC"). Neither the D&D costs nor the CTC
revenues are shown in the Financial Projections.
In addition to the waste disposal charge, PPL incurs expenses for additional
oil-site spent fuel storage. These expenses are estimated to be $2.5 million in
2001 and are projected to increase annually by the assumed inflation rate of
2.5%.
The capital fuel expenses are for the purchase, refining, enrichment, and
conversion of uranium into nuclear fuel and the fabrication and installation of
the nuclear fuel assemblies. PPL's share of the capital fuel costs, waste
disposal charges, and spent fuel storage costs are shown in Table 1-21. Also
shown is the total fuel expense (expense and capital), both on a total dollars
and $/MWh basis.
Table 1-20
Fuel Expenses and Prices
(Nominal $000s)
- -------------------------------------------------------------------------------------------------------------
Project Units 2001 2005 2010 2015 2020
- -------------------------------------------------------------------------------------------------------------
Griffith $ 39,643 34,362 43,942 47,264 50,832
$/MMBtu $5.65 $3.18 $3.71 $3.68 $3.89
- -------------------------------------------------------------------------------------------------------------
Wallingford $ 4,044 17,537 15,851 16,222 12,392
$/MMBtu $5.97 $3.77 $4.48 $5.22 $5.97
- -------------------------------------------------------------------------------------------------------------
Kings Park $ -- 20,789 16,291 20,744 17,164
$/MMBtu $0.00 $3.73 $4.47 $5.43 $6.22
- -------------------------------------------------------------------------------------------------------------
Lower Mt Bethel $ -- 63,595 85,282 88,286 93,673
$/MMBtu $0.00 $3.40 $4.04 $4.61 $5.41
- -------------------------------------------------------------------------------------------------------------
Starbuck $ -- 205,837 218,253 179,598 164,318
$/MMBtu -- 3.16 3.73 3.72 3.45
- -------------------------------------------------------------------------------------------------------------
Sundance $ -- 11,967 14,599 32,924 40,453
-----------
$/MMBtu -- 3.17 3.71 3.63 3.86
- -------------------------------------------------------------------------------------------------------------
University Park $ -- 15,606 32,663 54,755 46,289
-----------
$/MMBtu -- 3.34 3.92 4.27 4.71
- -------------------------------------------------------------------------------------------------------------
PA New CT's $ -- 26,795 34,443 37,619 36,364
$/MMBtu $0.00 $3.50 $4.14 $4.92 $5.65
- -------------------------------------------------------------------------------------------------------------
Total, Fuel $ 43,687 396,488 461,324 477,412 461.485
$/MMBtu $5.68 $3.28 $3.87 $4.04 $4.11
- -------------------------------------------------------------------------------------------------------------
A-63
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
As of July 2000, PPL had entered into uranium supply and conversion agreements
Uranerz Exploration & Mining Ltd., British Nuclear Fuels Ltd., and ConverDyn for
the supply and conversion of uranium oxide (U(3)O(8)) to uranium hexaflouride
(UF(6)) and/or the supply of UF(6). PPL's annual uranium requirements (expressed
as uranium oxide equivalent) is approximately 1.2 -- 1.3 million pounds. Through
is existing contracts, PPL has secured 100% of its supply requirements in 2000
and 50% of its requirements between 2001 and 2003. PPL's contracting approach is
typically to have multiple suppliers contracted with staggered multi-year terms
with one contract up for renewal each year.
Table 1-21
Fuel Expenses
(Nominal $000s)
- --------------------------------------------------------------------------------------------------
Year Capital Fuel Waste Disposal Spent Fuel Costs Total Fuel Costs Total Fuel Costs
Costs Charges ($/MWh)
- --------------------------------------------------------------------------------------------------
2001 55,803 14,363 2,520 72,686 4.76
- --------------------------------------------------------------------------------------------------
2002 55,306 14,461 2,583 72,350 4.70
- --------------------------------------------------------------------------------------------------
2003 54,788 14,712 2,648 72,148 4.61
- --------------------------------------------------------------------------------------------------
PPL has entered into an agreement with United States Enrichment Corporation
("USEC") which satisfies l00% of its enrichment requirements through the
refueling of Unit 1 in the spring of 2004. PPL has also entered into a contract
with Siemens Power Corp. for 100% of its fuel assembly fabrication requirements
through the Unit 1 refueling in 2004 with options to add two additional
refuelings for each unit. If the options are exercised by PPL, the fabrication
requirements will be satisfied for Unit 1 through the spring of 2008 and for
Unit 2 through the spring of 2007.
Stone & Webster did not review these contracts but was provided brief written
summaries and internal reports on the nuclear fuels program. In addition, Stone
& Webster interviewed the nuclear fuels manager to obtain an overview of the
nuclear fuels program.
Summary of Fuel Expenses
A summary of the fuel expenses is shown in Table 1-22, which includes the
existing fossil fuel-fired units in Pennsylvania and Maine (eastern units), the
existing fossil fuel-fired units in Montana (western units), the new
development units, and the nuclear units.
A-64
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-22
Summary of Fuel Expenses
(Nominal $000s)
- -----------------------------------------------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- -----------------------------------------------------------------------------------------------------------------------
Eastern Fossil Fuel-Fired Units
- -----------------------------------------------------------------------------------------------------------------------
Delivered Fuel $000 388,657 395,214 466,047 448,492 494,869
- -----------------------------------------------------------------------------------------------------------------------
SO(2) Allowances $000 -- 4,366 (12,065) (41,446) (42,866)
- -----------------------------------------------------------------------------------------------------------------------
NO(x) Allowances $000 (8,646) (3,912) (4,300) (22,438) (25,824)
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Subtotal, Fuel Expense $000 380,011 395,668 449,682 384,608 426,179
-------------------------------------------------------------------------------
$/MWh 14.17 14.74 16.53 15.40 16.92
- -----------------------------------------------------------------------------------------------------------------------
Western Fossil Fuel-Fired Units
- -----------------------------------------------------------------------------------------------------------------------
Delivered Fuel $000 41,561 38,465 40,537 42,893 45,478
- -----------------------------------------------------------------------------------------------------------------------
Allowances $000 (258) (369) (575) (651) (736)
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Subtotal, Fuel Expense $000 41,303 38,096 39,962 42,242 44,742
-------------------------------------------------------------------------------
$/MWh 5.56 4.36 4.44 4.69 4.97
- -----------------------------------------------------------------------------------------------------------------------
New Development Units
- -----------------------------------------------------------------------------------------------------------------------
Delivered Fuel $000 43,687 396,488 461,325 477,412 461,485
-------------------------------------------------------------------------------
$/MWh 41.18 24.01 28.49 30.90 31.59
- -----------------------------------------------------------------------------------------------------------------------
Nuclear Units
- -----------------------------------------------------------------------------------------------------------------------
Expensed Fuel Costs $000 16,883 17,930 18,296 18,709 19,177
- -----------------------------------------------------------------------------------------------------------------------
Capitalized Fuel Costs $000 55,803 57,562 65,126 73,684 83,367
- -----------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------
Subtotal, Fuel Expenses $000 72,686 75,492 83,422 92,393 102,544
-------------------------------------------------------------------------------
$/MWh 4.76 4.68 5.18 5.73 6.36
- -----------------------------------------------------------------------------------------------------------------------
Fuel Expense Summary
- -----------------------------------------------------------------------------------------------------------------------
Expensed Fuel Costs $000 481,883 848,182 969,264 922,972 951,583
- -----------------------------------------------------------------------------------------------------------------------
Capitalized Fuel Costs $000 55,803 57,562 65,126 73,684 83,367
- -----------------------------------------------------------------------------------------------------------------------
Total Fuel Costs $000 537,686 905,744 1,034,391 996,656 1,034,950
-------------------------------------------------------------------------------
$/MWh 10.63 13.28 15.10 15.21 15.94
- -----------------------------------------------------------------------------------------------------------------------
The average cost of fuel, on a $/MWh basis, is $11/MWh in 2001 and increases to
$16/MWh in 2020. The relative range of fuel costs in 2001 is from $5/MWh for the
nuclear units to $41/MWh for the gas-fired new development units, with the
delivered coal costs in the middle at $14/MWh for the eastern units and $6/MWh
for the western units. Fuel costs are the major cost incurred when generating
electricity. PPL's fuel costs, on average, are low due to the predominance of
low cost nuclear and coal baseload generation.
O&M Expenses
After fuel expenses, the cost of operating and maintaining the electric
generating facilities is the largest operating expense. The O&M expenses include
the labor expenses for the staff located at the facilities, contracted
maintenance expenses, plant administrative expenses, variable operating costs,
certain support costs, and miscellaneous expenses.
A-65
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Existing Fossil Fuel-Fired Generating Units
The O&M expenses for the fossil fuel-fired generating assets are shown for
select years between 2001 and 2020 in Table 1-23. The O&M expenses include
direct plant operating and maintenance costs and certain support service
provided by staff at the PPL headquarters in Allentown. It does not include
corporate overhead allocations or such items as property tax and insurance.
The primary O&M costs are for Brunner Island and Montour Stations. The O&M costs
for Brunner Island and Montour start out at a similar level in 2001. The Montour
costs are higher than the Brunner Island costs in 2005 due to SCR catalyst
replacement expenses. By 2010, the Montour expenses increase as a result of the
addition of scrubbers for the two units.
Table 1-23
O&M Expenses for Existing Fossil Fuel-Fired Units
(Nominal $000s)
- -------------------------------------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- -------------------------------------------------------------------------------------------------------------
O&M Expenses for Wholly-Owned Plants
- -------------------------------------------------------------------------------------------------------------
Brunner Island 41,500 45,808 51,828 58,638 66,344
- -------------------------------------------------------------------------------------------------------------
Martins Creek 27,000 29,803 33,719 38,150 43,164
- -------------------------------------------------------------------------------------------------------------
Montour 42,000 51,327 66,814 75,594 92,722
- -------------------------------------------------------------------------------------------------------------
Existing CT's 2,450 2,704 3,060 3,462 3,917
- -------------------------------------------------------------------------------------------------------------
Plant Support Services 22,360 24,681 27,925 31,594 35,746
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
Subtotal, Wholly-Owned Plants 135,310 154,324 183,346 207,439 241,892
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
O&M Expenses for Jointly-Owned Plants (PPL Share)
- -------------------------------------------------------------------------------------------------------------
Conemaugh 10,414 10,688 12,092 13,681 15,479
- -------------------------------------------------------------------------------------------------------------
Keystone 5,559 5,484 6,205 7,825 8,853
- -------------------------------------------------------------------------------------------------------------
Wyman 4 1,186 1,309 1,481 1,676 1,896
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
Subtotal, Jointly-Owned Plants 17,159 17,481 19,778 23,182 26,228
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
Total O&M Expenses 152,469 171,805 203,124 230,620 268,120
- -------------------------------------------------------------------------------------------------------------
The plant support services expense line item consists of the engineering and
support services for the Pennsylvania power plants. Approximately $5.0 million
of the plant support services is unallocated O&M expenses that are not budgeted
for any station but, based on PPL's experience, is required to address
unexpected maintenance items.
For the jointly-owned stations, the primary O&M costs are for Conemaugh and
Keystone. Conemaugh's O&M expenses are higher than Keystone's as it has
scrubbers on both units. In addition, with the purchase of 50% of Potomac
Electric Powers share of Conemaugh Station, PPL owns 16.25% of Conemaugh versus
12.34% of Keystone. The O&M expenses shown for the jointly-owned assets are
PPL's share of the total expenses.
New Development Units
The O&M expenses for the new generating assets are shown for select years
between 2001 and 2020 in Table 1-24. The O&M expenses include direct plant
operating and maintenance costs
A-66
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
and certain support service provided by staff at the PPL headquarters in
Allentown. It does not include all overhead allocations but does include an
allowance for property taxes.
The initial O&M costs are relatively low in 2001 ($8.9 million) due to the
limited number of new units in operation. By 2005 all the new units are in
operation and the O&M expense is $107.5 million. Aside from inflation, the major
variable in the O&M expenses shown in the table is the major maintenance costs.
This variability can be seen in the Griffith Energy O&M expenses in 2010 and
again in 2020. The same factor is involved in the high O&M expenses for the
Lower Mount Bethel Project in 2015.
PPL provided O&M information for the Kings Park, Starbuck, Sundance, University
Park and the Pennsylvania Peaking Plants. The O&M information included detailed
operating costs. The most significant cost is the major maintenance expenses.
The major maintenance expenses for the peaking units appeared to be overly
conservative and were reduced somewhat by Stone & Webster. The major maintenance
expense for Starbuck as underestimated and were increased to be consistent with
the major maintenance expenses for Griffith and Lower Mt Bethel.
Table 1-24
O&M Expenses
(Nominal $000s)
- --------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Griffith Energy 5,759 13,595 24,199 15,965 29,186
- --------------------------------------------------------------------------------
Wallingford 3,128 4,994 4,628 4,547 4,970
- --------------------------------------------------------------------------------
Kings Park -- 7,803 7,635 8,233 8,410
- --------------------------------------------------------------------------------
Lower Mt Bethel -- 8,660 13,053 20,039 14,313
- --------------------------------------------------------------------------------
Starbuck -- 43,554 47,971 52,885 58,357
- --------------------------------------------------------------------------------
Sundance -- 15,836 17,580 18,975 49,953
- --------------------------------------------------------------------------------
University Park -- 6,261 7,777 9,788 10,329
- --------------------------------------------------------------------------------
PA Peaking Plants -- 6,759 8,172 8,622 9,464
- --------------------------------------------------------------------------------
Total O&M Expenses 8,886 107,463 131,015 139,055 184,983
- --------------------------------------------------------------------------------
Nuclear Units
The benchmark for O&M expenses for a two-unit nuclear station such as
Susquehanna is approximately $195 million in 2000 dollars. While the 2000 budget
is below this benchmark, this is likely due to underfunding of certain O&M
functions that are being corrected in the following years. By 2004, when the
issues that required the additional O&M funding are addressed, the O&M expenses
fall back to a baseline level of approximately $199 million.
Hydroelectric Units
The expenses shown in the Financial Projections for the hydroelectric generating
assets includes the operation and maintenance costs for the wholly-owned assets
and the cost of associated support services, PPL's share of the operation and
maintenance costs for the jointly-owned assets and associated overhead and
indirect expenses and capital expenditures for both the wholly-owned and
jointly-owned assets.
The O&M expenses for the hydroelectric assets are shown for select years between
2001 and 2020 in Table 1-25. The O&M expenses include direct plant operating and
maintenance costs
A-67
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
and certain support service provided by staff at the PPL headquarters in
Allentown. It does not include overhead allocations or such items as property
tax and insurance.
Table 1-25
O&M Expenses
(Nominal $000s)
- --------------------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- --------------------------------------------------------------------------------------------
O&M Expenses for Wholly-Owned Plants
- --------------------------------------------------------------------------------------------
Holtwood 3,640 4,018 4,546 5,143 5,819
- --------------------------------------------------------------------------------------------
Wallenpaupack 2,310 2,550 2,885 3,264 3,693
- --------------------------------------------------------------------------------------------
Maine 5,100 5,629 6,369 7,206 8,153
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Subtotal, Wholly-Owned Plants 11,050 12,197 13,800 15,613 17,665
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
O&M Expenses for Jointly-Owned Plants
- --------------------------------------------------------------------------------------------
Safe Harbor 3,330 3,676 4,159 4,705 5,324
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Subtotal, Jointly-Owned Plants 3,330 3,676 4,159 4,705 5,324
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Total O&M Expenses 14,380 15,873 17,959 20,319 22,989
- --------------------------------------------------------------------------------------------
Summary of O&M Expenses
A summary of the O&M expenses is shown in Table 1-26, which includes the
existing fossil fuel-fired, new development, nuclear, and hydroelectric units.
After fuel expenses. O&M expenses are the major cost incurred when generating
electricity.
The average O&M expense, on a $/MWh basis, is $8/MWh in 2001 and increases to
$13/MWh in 2020. The relative range of fuel costs in 2001 is from $5/MWh for the
existing fossil fuel-fired units to $13/MWh for the nuclear units with the O&M
expenses for the gas-fired new development units in the middle at $8/MWh.
The O&M expenses, as shown on a $/MWh basis, are sensitive to the projected
generation. For the baseload units (the existing fossil fuel-fired and nuclear
units) and the hydroelectric units, the O&M expense on a $/MWh basis is stable
and varies at or close to the assumed inflation rate. For the new development
units, the O&M expense, on a $/MWh basis, is over $8/MWh in 2001 but decreases
to under $7/MWh in 2005. By 2005, the currently announced new projects are all
in operation. In addition, the annual generation from these units peaks in 2005
at over 8 million MWh. By 2020, the O&M expense has risen to $13/MWh as a result
of the projected annual generation dropping to under 5 million MWh.
A-68
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-26
Summary of O&M Expense
(Nominal $000s)
- ------------------------------------------------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- ------------------------------------------------------------------------------------------------------------------------
Existing Fossil Fuel-Fired Units
- ------------------------------------------------------------------------------------------------------------------------
O&M Expenses $000 135,310 154,324 183,346 207,439 241,892
---------------------------------------------------------------------------------
$/MWh 5.04 5.75 6.74 8.31 9.60
- ------------------------------------------------------------------------------------------------------------------------
New Development Units
- ------------------------------------------------------------------------------------------------------------------------
O&M Expenses $000 8,886 107,463 131,015 139,055 184,983
---------------------------------------------------------------------------------
$/MWh 8.38 6.51 8.09 9.00 12.66
- ------------------------------------------------------------------------------------------------------------------------
Nuclear Units
- ------------------------------------------------------------------------------------------------------------------------
O&M Expenses $000 195,472 202,898 229,561 259,727 293,857
---------------------------------------------------------------------------------
$/MWh 12.79 12.59 14.24 16.12 18.23
- ------------------------------------------------------------------------------------------------------------------------
Hydroelectric Units
- ------------------------------------------------------------------------------------------------------------------------
O&M Expenses $000 14,380 15,873 17,959 20,319 22,989
---------------------------------------------------------------------------------
$/MWh 10.77 12.61 14.26 16.14 18.26
- ------------------------------------------------------------------------------------------------------------------------
O&M Expense Summary
- ------------------------------------------------------------------------------------------------------------------------
O&M Expenses $000 354,049 480,557 561,880 626,539 743,720
---------------------------------------------------------------------------------
$/MWh 7.96 7.91 9.24 10.84 13.01
- ------------------------------------------------------------------------------------------------------------------------
1.8.2.3 Montana Operating Expenses
The expenses for the Montana fossil-fired and hydroelectric generating assets
are shown separately in the Financial Projections. The fuel, O&M, and other
expenses (including non-income taxes) for these assets are shown as a separate
line item in the operating expenses in the Financial Projections. The PPL
Montana Offering Memorandum was used as a reference for the operating expenses
and was supplemented with additional data and information obtained during our
recent site visits can be referenced for additional details about the expenses
associated with the Montana assets.
1.8.2.4 Non-Income Taxes
Non-income taxes shown in the Financial Projections include property taxes,
capital stock taxes, and gross receipts taxes for the domestic generation
facilities. The non-income taxes in 2001 are estimated to be $47 million. The
non-income taxes decrease over time as the capital stock taxes are reduced and
the gross receipts taxes are eliminated. The non-income taxes for the Montana
plants was obtained from the PPL Montana Offering Memorandum. All other
information on the non-income taxes were provided by PPL. The non-income taxes
were not reviewed by Stone & Webster. No gross receipts taxes are assumed for
the new contract with Montana Power. Also the 2001 gross receipts taxes may be
overstated as the PLR revenues shown are net of the gross receipts taxes. By
2012, the non-income taxes are reduced to $22 million year and are projected to
increase thereafter by the assumed inflation rate.
A-69
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
1.8.2.5 Capital Expenditures
Existing Fossil Fuel Fired Units
The capital expenses for the fossil fuel-fired plants are shown for select years
in Table 1-29. The capital expenses shown in the table for 2001, 2005, and 2010
include a portion of major environmental projects. In 2001, the capital expenses
include the balance of the SCR system for Unit 1 at Montour Station. In 2005,
the capital expenses include the balance of the SCR system for Unit 3 at Brunner
Island Station. Finally, in 2010 a portion of the scrubber costs are included
for Montour. The capital expenses for Conemaugh, Keystone, and Wyman Unit 4 are
PPL's ownership share. The other capital expenses are for pooled projects and
unbudgeted capital expenses.
Table 1-29
Capital Expenses
(Nominal $000s)
- -----------------------------------------------------------------------------------
2001 2005 2010 2015 2020
- -----------------------------------------------------------------------------------
Brunner Island 15,525 51,120 29,391 19,869 22,480
- -----------------------------------------------------------------------------------
Martins Creek 9,580 17,531 3,901 4,415 4,995
- -----------------------------------------------------------------------------------
Montour 66,934 3,798 61,351 17,661 19,982
- -----------------------------------------------------------------------------------
CT's 140 -- -- 221 250
- -----------------------------------------------------------------------------------
Conemaugh 3,777 1,201 2,600 2,942 3,328
- -----------------------------------------------------------------------------------
Keystone 6,405 1,250 1,974 2,234 2,527
- -----------------------------------------------------------------------------------
Wyman4 1,000 1,000 1,000 1,131 1,280
- -----------------------------------------------------------------------------------
Other 3,836 19,325 6,925 7,835 8,865
- -----------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------
Total Capital Expenditures 107,197 95,225 107,142 56,308 63,707
- -----------------------------------------------------------------------------------
Nuclear and Hydroelectric Units
PPL's share of the capital project expenses for Susquehanna are projected to be
$38 million in 2001. The capital expenses peak in 2003 at $68 million and fall
back to $49 million in 2004 and $35 million in 2005. The capital expense in this
time period are related to major projects such as the replacement of major
elements of the steam turbines and projects to improve the reliability of the
plant. Starting in 2006, the capital project expenses are projected to stabilize
at $18 million and are projected to increase thereafter at the assumed inflation
rate.
The capital expenses for the hydroelectric projects are projected to be
approximately $7.7 million per year (Pennsylvania and Maine units) in 2001
dollars and address routine capital expenses.
1.8.2.6 Other Debt Payments
The existing debt payments for the Montana assets were obtained from the PPL
Montana LLC Offering Memorandum.
For the Lower Mount Bethel Project, annual lease payments are estimated to be
$36 million in 2004 and decrease over time to $30 million in 2020. The lease
payments for the simple cycle peaking units starts at $27 million in 2002, and
increases to $77 million in 2003 with the addition of more units in 2003. Once
all these units are in operation in 2004, the lease payments for the
A-70
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
simple cycle peaking units are approximately $91 million per year. The lease
payments were provided by PPL.
No initial capital costs and/or schedule of debt payments have been provided on
the Starbuck Project.
1.8.3 International Distribution
Stone & Webster prepared Financial Projections for PPL's international
distribution companies from 2001 through 2020. The Financial Projections
consists of a base case, the result of which are shown below for select years:
2001 2002 2003 2005 2010 2015 2020
---- ---- ---- ---- ---- ---- ----
Energy Sold (MWh) 4,233,714 4,559,276 5,039,637 5,885,931 8,312,263 9,866,708 11,163,274
Operating Revenues ($000)
Energy Sales 331,125 352,568 405,017 511,371 781,857 922,659 1,043,903
Other Income 22,427 23,387 25,735 29,010 39,838 49,245 55,716
- ------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 353,552 375,955 430,751 540,382 821,695 971,903 1,099,619
- ------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 162,903 169,790 202,286 266,555 407,919 482,666 546,092
Other Expenses 103,460 104,680 111,473 125,668 167,676 197,981 223,997
- ------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 266,364 274,470 313,759 392,222 575,595 680,647 770,090
- ------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 87,189 101,485 116,993 148,159 246,100 291,256 329,530
Non-Operating Revenues
($000)
Interest income 2,186 3,224 2,371 1,577 2,377 2,777 3,142
Other Income 2,797 3,161 3,549 4,021 5,230 6,991 7,910
Dividends from Affiliates (3,483) (251) 1,802 1,278 7,018 9,382 10,615
- ------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 1,500 6,134 7,722 6,876 14,624 19,151 21,667
- ------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses
($000)
Interest Expense -- -- -- -- -- -- --
Change in Working Capital 16,733 2,851 2,904 4,404 5,299 6,388 7,228
Taxes 7,146 9,959 12,756 20,455 48,454 56,308 63,707
- ------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Expenses 23,879 12,810 15,660 24,859 53,753 62,696 70,935
- ------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 84,299 69,333 39,643 50,018 44,023 53,049 60,020
- ------------------------------------------------------------------------------------------------------------------------------
Cash Available (19,489) 25,476 69,412 80,159 162,948 194,662 220,242
- ------------------------------------------------------------------------------------------------------------------------------
The projections shown above are for the three international distribution
companies reviewed by Stone & Webster -- CEMAR, DelSur and Emel. PPL owns
between 80% and 95% of these companies. The projections are based on the
business plans prepared for these companies by PPL Global. The projections in
the business plan were adjusted by Stone & Webster as appropriate to develop a
reasonable set of financial projections that were consistent with the condition
of the equipment, the service expectations, economic growth, etc. These
adjustments resulted in lower projections of cash available than that shown in
the business plans. In the near term, there are major capital requirements in
CEMAR associated with the implementation of a metering plan. These capital costs
depress the cash available in 2001 and 2002.
A-71
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
The cash flows from the international distribution companies are based on
unrepatriated cash flows. Taxes or other costs associated with repatriating the
cash flows from these companies to the U.S. have not been included or estimated.
The review of the international distribution companies was initially performed
in the fall of 2000 and was updated in July 2001. Since out initial review,
there were two major earthquakes in El Salvador, which has likely affected the
condition and performance of DelSur, which is located in that country
1.8.4 PPL Overhead
PPL's overhead expense in 2001 is projected to be $156 million, which includes a
credit of $18 million for AEC's share of the overhead expenses associated with
Susquehanna. PPL projects its overhead expenses to increase to $173 million in
2003 after which it is projected to increase at the assumed annual inflation
rate of 2.5%. Stone & Webster did not review PPL's overhead expense projections.
1.8.5 Debt Service Coverages
The debt service used in the Financial Projections is shown in Table 1-30. The
annual debt service payments were provided by PPL. Also shown in the table are
the debt service coverage ratios (DSCRs) for the base case and two sensitivity
cases (high case and low case).
The debt service is projected to decrease from $126 million in 2001 to $60
million in 2002. From 2003 through 2008 the debt service varies between $62 and
$65 million a year. For 2009 through 2020, the debt service is constant at $64
million a year.
A-72
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Table 1-30
Debt Service and Coverage Ratios
(Nominal $000s)
- -----------------------------------------------------------------------------------------
Year Debt Service Base Case High Case Low Case
DSCR DSCR DSCR
- -----------------------------------------------------------------------------------------
2001 126,828 5.2 x 5.3 x 4.0 x
- -----------------------------------------------------------------------------------------
2002 60,361 17.5 x 19.4 x 6.2 x
- -----------------------------------------------------------------------------------------
2003 62,304 11.3 x 13.4 x 8.0 x
- -----------------------------------------------------------------------------------------
2004 64,029 11.1 x 13.8 x 8.4 x
- -----------------------------------------------------------------------------------------
2005 63,996 15.2 x 14.5 x 12.0 x
- -----------------------------------------------------------------------------------------
2006 64,769 18.7 x 17.8 x 15.1 x
- -----------------------------------------------------------------------------------------
2007 64,525 19.4 x 18.4 x 15.3 x
- -----------------------------------------------------------------------------------------
2008 63,978 19.3 x 18.2 x 14.7 x
- -----------------------------------------------------------------------------------------
2009 64,009 20.0 x 18.8 x 15.1 x
- -----------------------------------------------------------------------------------------
2010 64,009 26.4 x 27.0 x 15.1 x
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
Average 2001 - 2010 16.4 x 16.7 x 11.4 x
- -----------------------------------------------------------------------------------------
Minimum 2001 - 2010 5.2 x 5.3 x 4.0 x
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
Average 2001 - 2005 12.1 x 13.3 x 7.7 x
- -----------------------------------------------------------------------------------------
Average 2006 - 2010 18.7 x 17.8 x 14.7 x
- -----------------------------------------------------------------------------------------
The DSCR for the base case averages 16.4 times the debt service. The minimum
DSCR is in 2001 at 5.2 times the debt service.
For the high case, the Market Consultant prepared additional projections of the
energy generation and forward prices. Generally, the high case differs from the
base case in that the market projections are run based on a higher peak demand
growth rate, a higher energy growth rate, and higher gas and oil prices. For the
specific differences between the high and base cases, the Market Consultant's
report should be read. The DSCR for the high case averages 16.7 times the debt
service. The minimum DSCR is in 2001 at 5.3 times the debt service.
For the low case, the Market Consultant prepared additional projections of the
energy generation and forward prices. Generally, the low case differs from the
base case in that the market projections are run based on a lower peak demand
growth rate, a lower energy growth rate, lower gas and oil prices, and lower new
equipment costs. For the specific differences between the low and base cases,
the Market Consultant's report should be read. The DSCR for the high case
averages 11.4 times the debt service. The minimum DSCR is in 2001 at 4.0 times
the debt service.
1.9 Conclusions
Set forth below are the principal opinions which we have reached regarding the
review of PPL Energy Supply. The opinions are shown in two groups, one for the
domestic electric generating facilities and the other for the international
electric distribution companies. For a complete
A-73
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
understanding of the assumptions upon which these opinions are based, the Report
should be read in its entirety.
Domestic Electric Generation Facilities
On the basis of our review and the assumptions set forth in the Report, Stone &
Webster is of the opinion that:
1) The electric generating facilities reviewed by Stone & Webster were found
to be well maintained and generally in good condition as compared to
similar facilities of the same age. With the continuation of the existing
condition monitoring programs and the implementation of the forecasted
overhauls and capital projects, these electric generating facilities
should continue to provide reliable power generation.
2) Stone & Webster reviewed and provided data that was used as inputs to the
Market Consultant's analysis. The key input data, such as claimed
capacity, equivalent availability factor, and full load heat rate were
reasonable and were generally consistent with recent historic experience.
3) The normal claimed capacities of the Assets are based on values reported
to the power pools. With planned maintenance and overhauls, it can be
expected that the normal claimed capacities will not change materially
during the period shown in the Financial Projections. In some cases,
equipment is being upgraded and will result in increased capacity.
Examples of this are the uprate of the Susquehanna Station and a number of
the Montana hydroelectric assets.
4) The full load heat rates for the Assets that were provided to the Market
Consultant for use in their model were developed from data provided by
PPL. The average heat rates used by Stone & Webster are, for the most
part, similar to the recent average heat rates reported for the electric
generating units. The projected performance of the electric generating
units, that is based on the heat rate assumptions, accurately reflects the
condition and capability of the electric generating units during the
period shown in the Financial Projections.
5) The Assets are technically capable of performing at the capacity factors
projected by the Market Consultant.
6) The O&M expenses forecasted by PPL are consistent with the staffing and
operating plan and recent historical expenses for the electric generating
facilities. The projected staffing is essentially unchanged from the
current staffing. The O&M expenses appear reasonable and adequate to meet
PPL's operation, maintenance and performance objectives.
7) The overhaul schedules developed by PPL are prudent and consistent with
current and projected operations. The overhaul expenses forecasted in the
Financial Model consistent with the overhaul schedules and are adequate to
support the continued operation of the Assets through 2020.
8) The capital expenses are for major environmental projects, new development
projects, ongoing repairs/replacements, and the procurement of nuclear
fuels. The on-going repair/replacement expenses projected for the Assets
by PPL are reasonable and consistent with condition of the assets and the
projected generation.
9) PPL has substantial portions of its near-term nuclear fuel requirements
under contract. The all-in cost of supplying, processing, and enriching
the uranium and in fabricating and
A-74
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
installing the fuel assemblies is comparable to the cost incurred by other
operators of nuclear power plants.
10) PPL also has a substantial portion of its coal supply under contract. The
coal supply comes from multiple sources and PPL tries to optimize the coal
supply and transportation costs with the requirements of the coal-fired
stations. PPL owns most of the unit trains used to transport the coal and
leases the balance of its requirements. PPL has coal transportation
contracts with Norfolk Southern and CSX that allow it to transport coal
from a variety of sources.
11) The projects under development are either gas-fired combined cycle
projects or simple cycle projects. The combustion turbine technology used
on the projects is proven or is a variation of a proven design. The new
projects represent an important addition to PPL's generating portfolio as
they add geographical, fuel, and technology diversity to the portfolio.
The projects announced to date likely represent only the initial core
group of projects, particularly for the simple cycle peaking plants.
12) The electric generating facilities are in compliance with current permit
requirements. PPL has well defined environmental, health and safety
program and has the expertise and capacity to recognize the environmental
issues involved. Its approach to the solutions to the environmental issues
is reasonable based on our experience.
13) PPL has accumulated excess SO(2) allowances and these banked allowances
will allow PPL to operate for at least several years before the purchase
of additional SO(2) allowances will be required. Units 1 and 2 at
Conemaugh Station and Units 1, 2, and 3 at Colstrip Station are the only
units that are currently equipped with flue gas desulfurization ("FGD")
systems. PPL has developed plans to install FGD systems at Montour, which
will be implemented based on a number of factors including the cost of
allowances and future environmental regulations. For purposes of the
Financial Projections, it is assumed that two FGD systems will be
installed at Montour and be operational in 2010. After the FGD systems are
installed, PPL is projected to have sufficient SO(2) allowances.
14) PPL has installed NO(x) control systems at its coal-fired plants. All the
coal-fired units are equipped with low NO(x) burners or low NO(x) burners
and overfire air. Recently, PPL successfully completed the installation of
SCR systems for both units at Montour. An SCR system is also under
development for the two units at Keystone with a planned in-service date
of May 2003.
15) No environmental site assessments were prepared for the existing electric
generating facilities. There are no immediate major environmental
remediation projects at any of these facilities. Given the past use of the
sites, it is likely that there will be some site remediation required.
16) The existing electric generating facilities should have a remaining life
of at least twenty to twenty-five years, with some of the facilities
likely to have longer remaining lives. The new projects can be expected to
have useful lives in excess of thirty years.
17) A major source of revenue for PPL is from serving PP&L Electric's PLR
load. The projections for the PLR load show limited migration for
residential and industrial customers, but a substantial migration for
commercial customers. Overall, the PLR load is projected to equal 90% of
PP&L Electric's load in 2001 and 94% of PP&L Electric's load in 2009. The
revenues from PLR sales are projected to be lower than the cost of
purchasing energy and capacity from the market to supply the PLR load,
based on using data supplied by the Market Consultant.
A-75
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
International Distribution Companies -- Conclusions
18) Emel's service area ranges from predominantly rural for Emelectric,
Emelat, and Elfec to urban for Elecda, with Emelari and Eliqsa somewhere
in between. The region covered by Emel's companies is in northern and
central Chile and central Bolivia. For several of the companies, the
mining industry is a major customer. In general, the electric use per
customer for Emel is low as compared to some other distribution companies
in Central and Latin America.
19) Emel's distribution assets appear to be in good condition and are adequate
to meet its present service needs, but in some cases the system appears to
be at capacity. Additional investment to increase capacity and incorporate
more reliable configurations will likely be required.
20) Emel operates at a high employee to customer ratio, indicating an
efficiently operated system. The low number of employees is due in part to
the high level of outsourcing undertaken by Emel. Emel's operating costs
are relatively low, both on a $/customer and a $/MWh sold basis.
Significant additional cost savings are projected by Emel, but are not
likely to be achieved to the extent planned.
21) Emel's technical and non-technical losses are moderate to low indicating a
well-managed system. The quality of service indices computed for the Emel
companies is good for a developing country but will need to be improved to
meet more stringent performance requirements being imposed by Chile.
22) CEMAR's service area is geographically dispersed with small load centers.
The region covered has one of the lowest per capita incomes in Brazil.
Major investments are being made in the region and the economy has been
growing at a rate greater than the rest of Brazil. The loads served are
primarily residential (40%) with an unusually high level of public loads
(22%). The overall kWh use per customer is low.
23) The CEMAR distribution system has suffered from a lack of investment. The
medium and low voltage distribution systems vary by location from fair to
poor and fair to good. The system has poor voltage control and reactive
compensation due to the use of long feeder lines and low quality
components. The system also experiences a high level of distribution
system transformer failures, which is an indication of an overloaded
system.
24) The technical and non-technical losses of electricity in the CEMAR system
are high. CEMAR has set aggressive goals for loss reduction and is
undertaking a program to meter all its users to address the non-technical
losses. Additional investment in the system will be required to address
the technical losses experienced by CEMAR.
25) CEMAR's operating structure is more typical of developing countries. It
has lower customer to employee ratios than the other companies but has
plans to reduce the work force so this measure of efficiency should
improve. CEMAR has low costs per customer, but this is likely an indicator
of under-investment in system rather than an efficient use of resources as
the CEMAR system has performed poorly from a reliability standpoint.
26) CEMAR is projecting the expenditure of significant capital in 2001 and
2002 to address many issues with its system. Longer-term, its capital plan
is comparable to that experienced in other developing countries.
A-76
Independent Technical Review
PPL Energy Supply LLC
- --------------------------------------------------------------------------------
27) For DelSur, the service area covers a mix of urban and rural areas.
Customers are overwhelmingly residential (93%) but a substantial portion
of the load (49%) is due to a small group of customers (0.7%). The overall
kWh use per customer is low.
28) The DelSur distribution system appears to be in good condition. The
technical and nontechnical losses of electricity in the DelSur system are
low for developing countries and comparable to losses experienced in some
developed countries. Even so, DelSur is maintaining it focus on further
reducing losses through the implementation of a detailed loss reduction
program.
29) DelSur appears to be a well run, efficient companies with high customer to
employee ratios and low cost per customer and per MWh of sales.
A-77
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
EXHIBIT I
BASE CASE
Consolidated Cash Flow Summary
Cash Flow Summary for Existing Fossil-Fired Generating Units (Non-Montana)
Cash Flow Summary for Projects Under Development
Cash Flow Summary for Nuclear Generating Assets
Cash Flow Summary for Hydroelectric Generating Assets (Non-Montana)
Cash Flow Summary for Montana Generating Assets
A-78
Exhibit I Independent Technical Review
Financial Projections - Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Consolidated Cash Flow Summary
A-79
PPL Consolidation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285 285
Pennsylvania New Projects -- 630 630 1,232 1,232 1,232
Pennsylvania Nuclear 1,975 1,988 2,023 2,068 2,083 2,083
Other New Projects 248 1,215 1,755 1,755 2,955 2,955
Montana Fossil and Hydro 1,208 1,208 1,208 1,221 1,273 1,307
Maine 95 95 95 95 95 95
- ------------------------------------------------------------------------------------------------------------------------------------
Total Net Capacity 9,038 10,649 11,223 11,883 13,150 13,184
- ------------------------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,821,267 26,998,227 26,372,479 26,607,535 26,842,592 26,827,299
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects -- -- 530,264 2,950,975 3,431,548 3,509,529
Pennsylvania Nuclear 15,279,643 15,384,107 15,651,071 15,999,286 16,115,357 16,115,357
Other New Projects 1,060,942 2,436,507 3,898,321 3,587,978 13,079,739 12,897,805
Montana Fossil and Hydro 7,422,967 8,332,838 8,332,838 8,414,353 8,728,767 8,941,441
Montana Purchases - Basin 364,090 364,090 148,608 148,608 148,608 148,608
Maine 327,500 250,987 250,987 250,987 250,987 250,987
NUG Contracts 2,537,187 2,537,187 2,537,187 2,537,187 2,537,187 2,537,187
- ------------------------------------------------------------------------------------------------------------------------------------
Total Net Generation 54,821,552 57,311,901 58,729,713 61,504,867 72,142,743 72,236,171
- ------------------------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 31,043,565 30,375,744 31,110,038 32,206,476 33,677,785 34,404,881
Other Contract Sales 3,485,801 3,303,729 3,283,033 1,156,654 -- --
Net Market Sales (Purchases) 10,302,908 12,786,216 13,655,215 17,322,207 27,230,138 26,332,899
Montana Market Sales 2,573,057 4,180,472 4,353,734 4,435,249 4,749,663 4,962,337
Montana Contract Sales 5,214,000 4,516,456 4,127,712 4,127,712 4,127,712 4,127,712
- ------------------------------------------------------------------------------------------------------------------------------------
Total Power Sales 52,619,331 55,162,617 56,529,732 59,248,297 69,785,298 69,827,829
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 296,276 475,004 359,057 376,570 501,835 505,522
Merchant Energy Sales 282,703 369,337 383,378 491,155 786,995 787,072
Contact Capacity Sales (Purchases) 54,000 63,000 66,600 30,900 -- --
Contract Energy Sales (Purchases) 1,131,869 1,201,237 1,157,977 1,185,828 1,266,291 1,422,137
Montana Merchant Revenues 236,864 361,476 210,251 185,466 212,203 230,151
Montana Contract Revenues 101,985 121,241 156,748 156,336 155,882 155,517
Trading -- -- -- -- -- --
Other 26,565 25,169 23,896 22,622 21,949 21,275
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,130,261 2,616,463 2,357,906 2,448,877 2,945,154 3,121,674
- ------------------------------------------------------------------------------------------------------------------------------------
2007 2008 2009 2010
---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317
Maine 95 95 95 95
- -------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195
- -------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,812,152 27,241,045 27,226,193 27,211,473
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 3,589,782 3,672,401 3,757,486 3,845,144
Pennsylvania Nuclear 16,115,357 16,115,357 16,115,357 16,115,357
Other New Projects 12,733,017 12,585,830 12,456,839 12,346,793
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin 148,608 148,608 148,608 99,072
Maine 250,987 250,987 250,987 250,987
NUG Contracts 2,537,187 1,772,806 1,268,608 95,335
- -------------------------------------------------------------------------------------------------------
Total Net Generation 72,198,391 71,798,344 71,235,379 67,975,462
- -------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 35,125,621 35,826,477 36,539,915 --
Other Contract Sales -- -- -- --
Net Market Sales (Purchases) 25,462,025 24,312,062 22,985,719 60,873,047
Montana Market Sales 7,039,039 9,053,839 9,053,839 9,004,303
Montana Contract Sales 2,112,912 98,112 98,112 98,112
- -------------------------------------------------------------------------------------------------------
Total Power Sales 69,739,597 69,290,491 68,677,585 69,975,462
- -------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 509,280 505,671 504,302 1,099,219
Merchant Energy Sales 786,783 783,391 764,921 2,213,674
Contact Capacity Sales (Purchases) -- -- -- --
Contract Energy Sales (Purchases) 1,476,390 1,588,850 1,696,265 (5,983)
Montana Merchant Revenues 322,880 418,245 432,311 444,212
Montana Contract Revenues 74,353 (6,855) (7,425) (4,804)
Trading -- -- -- --
Other 21,302 20,328 19,055 6,000
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,190,987 3,309,630 3,409,428 3,752,319
- -------------------------------------------------------------------------------------------------------
A-80
PPL Consolidation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 481,883 565,385 608,528 647,161 848,182 896,111
O&M 401,515 431,989 470,252 483,442 531,335 542,159
Other Montana Operating Expenses 21,581 22,123 22,667 23,193 23,774 24,356
Nuclear Decommissioning Expense 23,666 21,969 20,696 19,422 18,149 16,875
- -----------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 928,645 1,041,466 1,122,143 1,173,218 1,421,441 1,479,500
- -----------------------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 47,435 40,986 38,880 36,727 35,240 34,259
Operating Cash Flow ($000) 1,154,181 1,534,011 1,196,883 1,238,932 1,488,473 1,607,915
Capital Expenditures ($000)
Pennsylvania Fossil 106,197 98,067 86,395 95,153 94,225 59,410
Pennsylvania Hydro 4,826 959 937 1,407 3,677 1,102
Pennsylvania New Projects -- -- -- -- -- --
Pennsylvania Nuclear Projects 37,710 49,500 67,500 48,600 35,100 18,329
Pennsylvania Nuclear Fuel 55,803 55,306 54,788 56,158 57,562 59,001
Other New Projects 53,496 -- -- -- -- --
Montana 23,472 50,409 48,248 48,457 56,970 19,048
Maine 3,878 4,503 9,080 5,965 1,140 1,250
- -----------------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 285,381 258,744 266,949 255,740 248,675 158,140
- -----------------------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 36,127 48,338 46,110 42,744 37,490 37,283
Lease Payments for Lower Mt Bethel ($000) -- -- -- 35,822 35,464 35,109
Lease Payments for New Peakers ($000) -- 26,488 76,669 91,198 91,198 91,198
===================================================================================================================================
Cash from Domestic Generation Assets 832,673 1,200,441 807,155 813,427 1,075,646 1,286,184
===================================================================================================================================
2007 2008 2009 2010
---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 920,777 972,996 1,001,618 969,264
O&M 564,436 611,850 598,603 619,321
Other Montana Operating Expenses 24,953 25,563 26,163 26,803
Nuclear Decommissioning Expense 15,602 14,328 13,055 --
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,525,768 1,624,737 1,639,439 1,615,388
- -------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 33,118 31,938 31,192 31,427
Operating Cash Flow ($000) 1,632,102 1,652,954 1,738,798 2,105,505
Capital Expenditures ($000)
Pennsylvania Fossil 60,042 105,478 150,621 106,142
Pennsylvania Hydro 1,123 1,145 1,167 1,190
Pennsylvania New Projects -- -- -- --
Pennsylvania Nuclear Projects 18,787 19,257 19,738 20,232
Pennsylvania Nuclear Fuel 60,476 61,988 63,538 65,126
Other New Projects -- -- -- --
Montana 13,663 13,456 13,710 14,085
Maine 1,256 1,263 1,269 1,276
- -------------------------------------------------------------------------------------------------------
Total Capital Expenditures 155,347 202,586 250,043 208,051
- -------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 35,219 37,209 38,847 40,501
Lease Payments for Lower Mt Bethel ($000) 34,758 34,411 34,066 33,726
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198
=======================================================================================================
Cash from Domestic Generation Assets 1,315,579 1,287,550 1,324,643 1,732,029
=======================================================================================================
A-81
PPL Consolidation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
International Distribution Assets
Cemar
PPL's Ownership % 84.7% 84.7% 84.7% 84.7% 84.7% 84.7%
Energy Sold (MWh) 2,188,477 2,385,269 2,644,653 2,940,281 3,249,269 3,583,229
Operating Revenues ($000)
Energy Sales 158,521 171,203 202,013 239,938 278,973 317,344
Other Income 9,721 10,059 10,735 11,518 12,354 13,241
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 168,242 181,262 212,748 251,456 291,327 330,584
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 56,694 58,635 78,622 101,511 125,498 150,758
Other Expenses 66,134 66,078 68,916 73,560 78,993 84,637
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 122,828 124,713 147,538 175,071 204,491 235,394
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 45,414 56,549 65,210 76,385 86,837 95,190
Non-Operating Revenues ($000)
Interest Income 616 372 123 24 22 --
Other Income -- -- -- -- -- --
Dividends from Affiliates -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 616 372 123 24 22 --
- ------------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Interest Expense
Change in Working Capital 4,655 1,542 1,351 2,581 2,639 2,446
Taxes 948 3,028 4,871 7,467 10,768 14,190
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 5,602 4,570 6,222 10,048 13,408 16,636
- ------------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 51,811 41,653 15,833 19,380 21,921 16,125
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Available from Cemar (11,384) 10,699 43,277 46,980 51,530 62,429
- ------------------------------------------------------------------------------------------------------------------------------------
2007 2008 2009 2010
---- ---- ---- ----
International Distribution Assets
Cemar
PPL's Ownership % 84.7% 84.7% 84.7% 84.7%
Energy Sold (MWh) 3,944,768 4,239,672 4,550,317 4,877,529
Operating Revenues ($000)
Energy Sales 355,634 389,326 421,751 460,279
Other Income 14,169 14,985 15,828 16,711
- ------------------------------------------------------------------------------------------------------
Total Operating Revenues 369,803 404,311 437,579 476,990
- ------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 165,442 181,326 198,493 217,026
Other Expenses 90,722 96,049 101,437 107,098
- ------------------------------------------------------------------------------------------------------
Total Operating Expenses 256,164 277,375 299,930 324,124
- ------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 113,639 126,937 137,649 152,865
Non-Operating Revenues ($000)
Interest Income 289 1,471 1,171 (16)
Other Income -- -- -- --
Dividends from Affiliates -- -- -- --
- ------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 289 1,471 1,171 (16)
- ------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Interest Expense
Change in Working Capital 3,590 2,842 2,532 3,200
Taxes 20,908 26,071 29,369 33,464
- ------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 24,498 28,913 31,901 36,665
- ------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 18,015 19,811 17,622 25,536
- ------------------------------------------------------------------------------------------------------
Cash Available from Cemar 71,415 79,684 89,297 90,648
- ------------------------------------------------------------------------------------------------------
A-82
PPL Consolation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
International Distribution Assets
Delsur
PPL's Ownership % 80.5% 80.5% 80.5% 80.5% 80.5% 80.5%
Energy Sold (MWh) 711,471 759,048 809,790 863,906 919,884 975,077
Operating Revenues ($000)
Energy Sales 67,797 69,474 76,366 83,672 94,823 115,885
Other Income 1,901 1,938 2,043 2,154 2,269 2,387
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 69,697 71,412 78,409 85,825 97,092 118,272
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 45,304 46,310 50,667 55,258 62,195 75,598
Other Expenses 11,746 12,013 12,918 13,886 15,022 16,601
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 57,049 58,322 63,585 69,144 77,217 92,199
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 12,648 13,090 14,824 16,681 19,875 26,074
Non-Operating Revenues ($000)
Interest Income 1,322 2,851 2,248 1,438 1,544 1,721
Other Income -- -- -- -- -- --
Dividends from Affiliates -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 1,322 2,851 2,248 1,438 1,544 1,721
- ------------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital (2,484) 74 311 333 482 837
Taxes 3,222 3,653 4,031 4,430 5,257 6,854
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 738 3,727 4,342 4,763 5,739 7,691
- ------------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 5,418 5,054 4,927 8,258 4,348 2,497
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Available from Delsur 7,814 7,161 7,802 5,098 11,332 17,606
- ------------------------------------------------------------------------------------------------------------------------------------
2007 2008 2009 2010
---- ---- ---- ----
International Distribution Assets
Delsur
PPL's Ownership % 80.5% 80.5% 80.5% 80.5%
Energy Sold (MWh) 1,023,831 1,075,023 1,128,774 1,185,212
Operating Revenues ($000)
Energy Sales 122,888 129,787 133,034 136,322
Other Income 2,489 2,597 2,708 2,824
- ---------------------------------------------------------------------------------------------------------
Total Operating Revenues 125,377 132,384 135,742 139,146
- ---------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 79,304 83,756 85,852 87,976
Other Expenses 17,503 18,501 19,389 20,319
- ---------------------------------------------------------------------------------------------------------
Total Operating Expenses 96,807 102,257 105,241 108,295
- ---------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 28,569 30,127 30,501 30,851
Non-Operating Revenues ($000)
Interest Income 1,786 1,861 1,911 1,962
Other Income -- -- -- --
Dividends from Affiliates -- -- -- --
- ---------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 1,786 1,861 1,911 1,962
- ---------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 368 310 181 186
Taxes 7,501 7,906 8,007 7,754
- ---------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 7,869 8,216 8,188 7,940
- ---------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 2,548 2,601 2,656 2,711
- ---------------------------------------------------------------------------------------------------------
Cash Available from Delsur 19,938 21,170 21,567 22,162
- ---------------------------------------------------------------------------------------------------------
A-83
PPL Consolidation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
International Distribution Assets
Emel
Emel's Ownership % of Companies 58.1% 58.2% 62.4% 60.9% 61.3% 62.5%
PPL's Ownership % of Emel 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%
Energy Sold (MWh) 1,333,766 1,414,958 1,585,194 1,627,142 1,716,778 1,834,613
Operating Revenues ($000)
Energy Sales 104,808 111,891 126,638 130,345 137,575 147,387
Other Income 10,805 11,390 12,957 13,461 14,388 15,586
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 115,612 123,281 139,595 143,806 151,963 162,973
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 60,905 64,845 72,997 75,248 78,862 84,014
Other Expenses 25,580 26,590 29,639 30,205 31,653 33,608
- ------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 86,486 91,435 102,636 105,452 110,515 117,622
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 29,126 31,846 36,959 38,354 41,448 45,351
Non-Operating Revenues ($000)
Interest Income 248 0 (0) 0 11 53
Other Income 2,797 3,161 3,549 3,742 4,021 4,332
Dividends from Affiliates (3,483) (251) 1,802 3,798 1,278 4,848
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues (438) 2,910 5,351 7,540 5,310 9,233
- ------------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 14,562 1,234 1,241 1,189 1,283 1,382
Taxes 2,977 3,279 3,854 4,038 4,430 4,893
- ------------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 17,538 4,513 5,095 5,227 5,712 6,275
- ------------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 27,070 22,627 18,883 18,153 23,750 13,760
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Available from Emel (15,919) 7,616 18,333 22,514 17,296 34,549
- ------------------------------------------------------------------------------------------------------------------------------------
====================================================================================================================================
Cash Available from Int'l. Dist. Assets (19,489) 25,476 69,412 74,592 80,159 114,584
====================================================================================================================================
2007 2008 2009 2010
---- ---- ---- ----
International Distribution Assets
Emel
Emel's Ownership % of Companies 63.0% 63.3% 63.4% 63.8%
PPL's Ownership % of Emel 95.0% 95.0% 95.0% 95.0%
Energy Sold (MWh) 1,939,376 2,038,957 2,137,292 2,249,521
Operating Revenues ($000)
Energy Sales 156,780 165,682 174,578 185,255
Other Income 16,713 17,835 18,987 20,304
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues 173,494 183,517 193,565 205,559
- -------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 88,543 93,191 97,785 102,916
Other Expenses 35,310 36,904 38,464 40,259
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 123,853 130,096 136,249 143,175
- -------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 49,641 53,422 57,316 62,384
Non-Operating Revenues ($000)
Interest Income 100 194 298 431
Other Income 4,611 4,832 5,036 5,230
Dividends from Affiliates 5,361 5,873 6,411 7,018
- -------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 10,072 10,898 11,745 12,678
- -------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 1,587 1,582 1,671 1,913
Taxes 5,479 5,997 6,535 7,236
- -------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 7,066 7,579 8,206 9,148
- -------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 14,274 14,742 15,206 15,776
- -------------------------------------------------------------------------------------------------------
Cash Available from Emel 38,373 41,999 45,649 50,138
- -------------------------------------------------------------------------------------------------------
=======================================================================================================
Cash Available from Int'l. Dist. Assets 129,726 142,853 156,514 162,948
=======================================================================================================
A-84
PPL Consolidation
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 44,762 46,412 47,537 48,725 49,944 51,192
PPL Energy Plus 28,032 29,127 27,867 28,564 29,278 30,010
IEC (Interstate Energy Co.) 33 34 35 36 37 38
PPL Global 2,424 2,553 2,660 2,727 2,795 2,865
PPL Services 36,443 37,410 38,313 39,271 40,253 41,259
Indirect Costs 61,870 70,918 75,881 77,778 79,722 81,716
Benefit Loading -- -- -- -- -- --
G&A Recovery from AEC (17,767) (18,408) (18,979) (17,992) (18,442) (18,903)
====================================================================================================================================
Non-Operating and G&A Expenses 155,797 168,046 173,314 179,108 183,586 188,176
====================================================================================================================================
====================================================================================================================================
Total Cash Available (1), (2) 657,387 1,057,871 703,253 708,911 972,219 1,212,593
====================================================================================================================================
Interest Expense 126,828 60,361 62,304 64,029 63,996 64,769
Debt Service Coverage Ratio 5.18 17.53 11.29 11.07 15.19 18.72
----------------------------------
Average 2001 - 2010 16.40
Minimum 2001 - 2010 5.18
Average 2001 - 2005 12.05
Average 2006 - 2010 18.72
----------------------------------
2007 2008 2009 2010
---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 52,472 53,784 55,128 56,507
PPL Energy Plus 30,760 31,529 32,317 33,125
IEC (Interstate Energy Co.) 39 40 41 42
PPL Global 2,936 3,010 3,085 3,162
PPL Services 42,290 43,348 44,431 45,542
Indirect Costs 83,758 85,852 87,999 90,199
Benefit Loading -- -- -- --
G&A Recovery from AEC (19,376) (19,860) (20,356) (20,865)
=========================================================================================================
Non-Operating and G&A Expenses 192,880 197,702 202,644 207,711
=========================================================================================================
=========================================================================================================
Total Cash Available (1), (2) 1,252,425 1,232,702 1,278,512 1,687,267
=========================================================================================================
Interest Expense 64,525 63,978 64,009 64,009
Debt Service Coverage Ratio 19.41 19.27 19.97 26.36
(1) Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
(2) The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-85
PPL Consolidation
Base Cash
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- -----------------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- -----------------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,803,671 26,421,304 25,618,842 25,282,578 24,967,185
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 3,768,914 3,696,364 3,627,090 3,560,747 3,497,036
Pennsylvania Nuclear 16,115,357 16,115,357 16,115,357 16,115,357 16,115,357
Other New Projects 12,193,845 12,075,019 11,993,009 11,951,043 11,952,965
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 250,987 250,987 250,987 250,987 250,987
NUG Contracts 40,364 40,364 40,364 39,258 --
- -----------------------------------------------------------------------------------------------------------------------------
Total Net Generation 69,184,440 68,610,695 67,656,950 67,211,271 66,794,831
- -----------------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 60,181,096 59,607,352 58,653,607 58,207,928 57,791,487
Montana Market Sales 8,905,231 8,905,231 8,905,231 8,905,231 8,962,463
Montana Contract Sales 98,112 98,112 98,112 98,112 40,880
- -----------------------------------------------------------------------------------------------------------------------------
Total Power Sales 69,184,440 68,610,695 67,656,950 67,211,271 66,794,831
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 1,115,665 1,132,987 1,150,596 1,168,484 1,186,001
Merchant Energy Sales 2,229,814 2,250,084 2,248,868 2,273,344 2,299,019
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) (2,421) (2,421) (2,421) (2,355) --
Montana Merchant Revenues 449,328 460,456 472,370 485,125 501,311
Montana Contract Revenues 2,034 2,076 2,119 2,164 921
Trading -- -- -- -- --
Other 6,000 6,000 6,000 6,000 3,000
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,800,420 3,849,182 3,877,533 3,932,762 3,990,251
- -----------------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- -------------------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- -------------------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 25,003,991 25,043,996 25,087,370 25,134,292 25,184,953
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 3,416,755 3,338,460 3,262,097 3,187,617 3,114,969
Pennsylvania Nuclear 16,115,357 16,115,357 16,115,357 16,115,357 16,115,357
Other New Projects 11,845,603 11,764,260 11,654,540 11,570,077 11,492,530
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 250,987 250,987 250,987 250,987 250,987
NUG Contracts -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Net Generation 66,643,994 66,506,360 66,381,651 66,269,631 66,170,096
- -------------------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 57,640,650 57,503,016 57,378,308 57,266,287 57,166,753
Montana Market Sales 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Contract Sales -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Power Sales 66,643,994 66,506,360 66,381,651 66,269,631 66,170,096
- -------------------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 1,200,297 1,214,774 1,229,437 1,244,286 1,200,172
Merchant Energy Sales 2,328,758 2,359,685 2,391,823 2,425,197 2,459,835
Contact Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) -- -- -- -- --
Montana Merchant Revenues 501,696 500,380 499,173 498,072 497,079
Montana Contract Revenues -- -- -- -- --
Trading -- -- -- -- --
Other -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 4,030,751 4,074,839 4,120,432 4,167,555 4,157,085
- -------------------------------------------------------------------------------------------------------------------------------
A-86
PPL Consolidation
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 964,561 961,040 927,542 924,815 922,972
O&M 620,943 736,808 715,800 686,895 692,841
Other Montana Operating Expenses 27,456 28,125 28,812 29,512 30,226
Nuclear Decommissioning Expense -- -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,612,959 1,725,973 1,672,154 1,641,222 1,646,039
- -----------------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 32,179 22,178 22,744 23,285 23,214
Operating Cash Flow ($000) 2,155,281 2,101,032 2,182,635 2,268,255 2,320,998
Capital Expenditures ($000)
Pennsylvania Fossil 49,987 51,237 52,517 53,830 55,176
Pennsylvania Hydro 1,219 1,250 1,281 1,313 1,346
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 20,737 21,256 21,787 22,332 22,890
Pennsylvania Nuclear Fuel 66,754 68,423 70,134 71,887 73,684
Other New Projects -- -- -- -- --
Montana 14,463 19,351 18,112 18,565 21,202
Maine 1,308 1,341 1,374 1,408 1,444
- -----------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 154,468 162,857 165,205 169,336 175,742
- -----------------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 40,922 41,406 44,330 45,820 39,783
Lease Payments for Lower Mt Bethel ($000) 33,389 33,055 32,724 32,397 32,073
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
=============================================================================================================================
Cash from Domestic Generation Assets 1,853,304 1,772,515 1,849,177 1,929,504 1,982,202
=============================================================================================================================
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 927,538 932,666 938,374 944,674 951,583
O&M 731,736 755,753 785,511 885,729 818,639
Other Montana Operating Expenses 30,956 31,704 32,476 33,264 34,096
Nuclear Decommissioning Expense -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,690,230 1,720,124 1,756,361 1,863,667 1,804,317
- -------------------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 23,123 23,701 24,293 24,899 25,522
Operating Cash Flow ($000) 2,317,397 2,331,015 2,339,778 2,278,989 2,327,247
Capital Expenditures ($000)
Pennsylvania Fossil 56,556 57,969 59,419 60,904 62,427
Pennsylvania Hydro 1,380 1,414 1,449 1,486 1,523
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 23,462 24,049 24,650 25,266 25,898
Pennsylvania Nuclear Fuel 75,526 77,415 79,350 81,334 83,367
Other New Projects -- -- -- -- --
Montana 19,505 19,993 20,492 21,004 21,529
Maine 1,480 1,517 1,555 1,593 1,633
- -------------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 177,909 182,357 186,915 191,588 196,377
- -------------------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 15,292 3,935 3,668 3,401 3,134
Lease Payments for Lower Mt Bethel ($000) 31,752 31,435 31,120 30,809 30,501
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
===============================================================================================================================
Cash from Domestic Generation Assets 2,001,246 2,022,090 2,026,876 1,961,993 2,006,036
===============================================================================================================================
A-87
PPL Consolidation
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
International Distribution Assets
Cemar First Year Operation:
PPL's Ownership % 84.7% 84.7% 84.7% 84.7% 84.7%
Energy Sold (MWh) 4,999,467 5,124,454 5,252,565 5,383,879 5,518,476
Operating Revenues ($000)
Energy Sales 471,786 483,581 495,670 508,062 520,764
Other Income 17,128 17,557 17,995 18,445 18,906
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 488,915 501,137 513,666 526,508 539,670
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 222,452 228,013 233,714 239,557 245,545
Other Expenses 109,776 112,520 115,333 118,216 121,172
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 332,228 340,533 349,047 357,773 366,717
- -----------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 156,687 160,604 164,619 168,735 172,953
Non-Operating Revenues ($000)
Interest Income (17) (17) (18) (18) (18)
Other Income -- -- -- -- --
Dividends from Affiliates -- -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues (17) (17) (18) (18) (18)
- -----------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 3,280 3,362 3,446 3,533 3,621
Taxes 34,301 35,159 36,038 36,939 37,862
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 37,581 38,521 39,484 40,471 41,483
- -----------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 26,174 26,829 27,499 28,187 28,891
- -----------------------------------------------------------------------------------------------------------------------------
Cash Available from Cemar 92,915 95,238 97,618 100,059 102,560
- -----------------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
International Distribution Assets
Cemar First Year Operation:
PPL's Ownership % 84.7% 84.7% 84.7% 84.7% 84.7%
Energy Sold (MWh) 5,656,438 5,797,849 5,942,795 6,091,365 6,243,649
Operating Revenues ($000)
Energy Sales 533,783 547,127 560,806 574,826 589,196
Other Income 19,379 19,864 20,360 20,869 21,391
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 553,162 566,991 581,166 595,695 610,587
- -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 251,684 257,976 264,426 271,036 277,812
Other Expenses 124,201 127,306 130,489 133,751 137,095
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 375,885 385,282 394,914 404,787 414,907
- -------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 177,277 181,709 186,252 190,908 195,681
Non-Operating Revenues ($000)
Interest Income (19) (19) (20) (20) (21)
Other Income -- -- -- -- --
Dividends from Affiliates -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues (19) (19) (20) (20) (21)
- -------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 3,711 3,804 3,899 3,997 4,097
Taxes 38,809 39,779 40,773 41,793 42,837
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 42,520 43,583 44,673 45,789 46,934
- -------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 29,614 30,354 31,113 31,891 32,688
- -----------------------------------------------------------------------------------------------------------------------------
Cash Available from Cemar 105,124 107,753 110,446 113,208 116,038
- -----------------------------------------------------------------------------------------------------------------------------
A-88
PPL Consolation
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
International Distribution Assets
Delsur
PPL's Ownership % 80.5% 80.5% 80.5% 80.5% 80.5%
Energy Sold (MWh) 1,214,843 1,245,214 1,276,344 1,308,253 1,340,959
Operating Revenues ($000)
Energy Sales 139,730 143,224 146,804 150,474 154,236
Other Income 2,894 2,967 3,041 3,117 3,195
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 142,625 146,190 149,845 153,591 157,431
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 90,176 92,430 94,741 97,109 99,537
Other Expenses 20,827 21,347 21,881 22,428 22,989
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 111,002 113,777 116,622 119,537 122,526
- -----------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 31,622 32,413 33,223 34,054 34,905
Non-Operating Revenues ($000)
Interest Income 2,011 2,062 2,113 2,166 2,220
Other Income -- -- -- -- --
Dividends from Affiliates -- -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 2,011 2,062 2,113 2,166 2,220
- -----------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 191 196 201 206 211
Taxes 7,948 8,146 8,350 8,559 8,773
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 8,139 8,342 8,551 8,764 8,983
- -----------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 2,779 2,848 2,919 2,992 3,067
- -----------------------------------------------------------------------------------------------------------------------------
Cash Available from Delsur 22,716 23,284 23,866 24,463 25,074
- -----------------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
International Distribution Assets
Delsur
PPL's Ownership % 80.5% 80.5% 80.5% 80.5% 80.5%
Energy Sold (MWh) 1,374,483 1,408,845 1,444,066 1,480,168 1,517,172
Operating Revenues ($000)
Energy Sales 158,092 162,044 166,096 170,248 174,504
Other Income 3,275 3,356 3,440 3,526 3,614
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 161,367 165,401 169,536 173,774 178,119
- -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 102,026 104,576 107,191 109,870 112,617
Other Expenses 23,563 24,153 24,756 25,375 26,010
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 125,589 128,729 131,947 135,246 138,627
- -------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 35,778 36,672 37,589 38,529 39,492
Non-Operating Revenues ($000)
Interest Income 2,276 2,332 2,391 2,451 2,512
Other Income -- -- -- -- --
Dividends from Affiliates -- -- -- -- --
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 2,276 2,332 2,391 2,451 2,512
- -------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 216 221 227 233 238
Taxes 8,992 9,217 9,447 9,683 9,926
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 9,208 9,438 9,674 9,916 10,164
- -------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 3,144 3,223 3,303 3,386 3,470
- -------------------------------------------------------------------------------------------------------------------------------
Cash Available from Delsur 25,701 26,344 27,002 27,677 28,369
- -------------------------------------------------------------------------------------------------------------------------------
A-89
PPL Consolidation
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
International Distribution Assets
Emel
Emel's Ownership % of Companies 75.3% 75.3% 75.3% 75.3% 75.3%
PPL's Ownership % of Emel 95.0% 95.0% 95.0% 95.0% 95.0%
Energy Sold (MWh) 2,724,441 2,792,552 2,862,365 2,933,924 3,007,273
Operating Revenues ($000)
Energy Sales 224,366 229,976 235,725 241,618 247,659
Other Income 24,591 25,205 25,836 26,481 27,143
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 248,957 255,181 261,561 268,100 274,802
- -----------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 124,644 127,760 130,954 134,228 137,583
Other Expenses 48,759 49,978 51,227 52,508 53,821
- -----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 173,403 177,738 182,181 186,736 191,404
- -----------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 75,554 77,443 79,379 81,364 83,398
Non-Operating Revenues ($000)
Interest Income 522 535 548 562 576
Other Income 6,334 6,492 6,654 6,821 6,991
Dividends from Affiliates 8,500 8,712 8,930 9,153 9,382
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 15,355 15,739 16,133 16,536 16,949
- -----------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 2,316 2,374 2,434 2,495 2,557
Taxes 8,763 8,982 9,207 9,437 9,673
- -----------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 11,080 11,357 11,641 11,932 12,230
- -----------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 19,107 19,584 20,074 20,576 21,090
- -----------------------------------------------------------------------------------------------------------------------------
Cash Available from Emel 60,723 62,241 63,797 65,392 67,027
- -----------------------------------------------------------------------------------------------------------------------------
=============================================================================================================================
Cash Available from Int'l. Dist. Assets 176,354 180,763 185,282 189,914 194,662
=============================================================================================================================
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
International Distribution Assets
Emel
Emel's Ownership % of Companies 75.3% 75.3% 75.3% 75.3% 75.3%
PPL's Ownership % of Emel 95.0% 95.0% 95.0% 95.0% 95.0%
Energy Sold (MWh) 3,082,454 3,159,516 3,238,504 3,319,466 3,402,453
Operating Revenues ($000)
Energy Sales 253,850 260,196 266,701 273,369 280,203
Other Income 27,822 28,518 29,231 29,961 30,710
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 281,672 288,714 295,932 303,330 310,913
- -------------------------------------------------------------------------------------------------------------------------------
Operating Expenses ($000)
Energy Purchases 141,023 144,549 148,162 151,866 155,663
Other Expenses 55,166 56,545 57,959 59,408 60,893
- -------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 196,189 201,094 206,121 211,274 216,556
- -------------------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 85,483 87,620 89,810 92,056 94,357
Non-Operating Revenues ($000)
Interest Income 590 605 620 636 651
Other Income 7,166 7,345 7,529 7,717 7,910
Dividends from Affiliates 9,617 9,857 10,104 10,356 10,615
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating Revenues 17,373 17,807 18,252 18,709 19,176
- -------------------------------------------------------------------------------------------------------------------------------
Non-Operating Expenses ($000)
Change in Working Capital 2,621 2,686 2,753 2,822 2,893
Taxes 9,915 10,163 10,417 10,677 10,944
- -------------------------------------------------------------------------------------------------------------------------------
Total Non-Operating and G&A Expenses 12,536 12,849 13,170 13,500 13,837
- -------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures ($000) 21,618 22,158 22,712 23,280 23,862
- -------------------------------------------------------------------------------------------------------------------------------
Cash Available from Emel 68,702 70,420 72,181 73,985 75,835
- -------------------------------------------------------------------------------------------------------------------------------
===============================================================================================================================
Cash Available from Int'l. Dist. Assets 199,528 204,516 209,629 214,870 220,242
===============================================================================================================================
A-90
PPL Consolidation
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 57,919 59,367 60,851 62,373 63,932
PPL Energy Plus 33,953 34,802 35,672 36,564 37,478
IEC (Interstate Energy Co.) 43 44 45 46 47
PPL Global 3,241 3,322 3,405 3,490 3,577
PPL Services 46,681 47,848 49,044 50,270 51,527
Indirect Costs 92,454 94,765 97,134 99,562 102,052
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (21,387) (21,922) (22,470) (23,031) (23,607)
=============================================================================================================================
Non-Operating and G&A Expenses 212,903 218,226 223,682 229,274 235,005
=============================================================================================================================
=============================================================================================================================
Total Cash Available (1), (2) 1,798,754 1,735,052 1,810,777 1,890,144 1,941,858
=============================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 28.10 27.11 28.29 29.53 30.34
--------------------------------
Average 2001 - 2010 16.40
Minimum 2001 - 2010 5.18
Average 2001 - 2005 12.05
Average 2006 - 2010 18.72
--------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 65,530 67,169 68,848 70,569 72,333
PPL Energy Plus 38,415 39,375 40,360 41,369 42,403
IEC (Interstate Energy Co.) 48 49 51 52 53
PPL Global 3,667 3,759 3,852 3,949 4,048
PPL Services 52,815 54,135 55,489 56,876 58,298
Indirect Costs 104,603 107,218 109,898 112,646 115,462
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (24,197) (24,802) (25,422) (26,058) (26,709)
===============================================================================================================================
Non-Operating and G&A Expenses 240,881 246,903 253,075 259,402 265,887
===============================================================================================================================
===============================================================================================================================
Total Cash Available (1), (2) 1,959,893 1,979,704 1,983,430 1,917,460 1,960,391
===============================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 30.62 30.93 30.99 29.96 30.63
(1) Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
(2) The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-91
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Cash Flow Summary for Existing Fossil-Fired Generating Units (Non-Montana)
A-92
PPL Existing Fossil Units
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Generation (MWh)
Brunner Island 10,560,721 10,560,721 10,300,016 10,430,369 10,560,721
Martins Creek 1,587,927 1,764,888 1,399,843 1,504,548 1,609,252
Montour 10,970,586 10,970,586 10,970,586 10,970,586 10,970,586
CT's -- -- -- -- --
Conemaugh 2,104,163 2,104,163 2,104,163 2,104,163 2,104,163
Keystone 1,597,869 1,597,869 1,597,869 1,597,869 1,597,869
Wyman 4 76,513 0 0 0 0
- ---------------------------------------------------------------------------------------------------------------------
Total Generation 26,821,267 26,998,227 26,372,479 26,607,535 26,842,592
- ---------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 623,729 813,423 374,880 407,285 441,077
Market Energy Sales 810,470 760,339 726,326 741,008 755,750
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 1,434,199 1,573,762 1,101,206 1,148,293 1,196,826
- ---------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 53.47 58.29 41.76 43.16 44.59
Expenses ($000)
Fuel
Fossil Fuel 375,157 415,138 390,244 382,555 380,313
Other Direct Fossil Fuel Expense 13,500 13,838 14,183 14,538 14,901
NO(x) Emission Reduction Credits (8,646) (4,199) 736 2,489 (3,912)
SO(2) Emission Reduction Credits 18,111 20,895 23,165 26,097 29,064
Banked SO(2) Allowances Used (18,111) (20,895) (23,165) (26,097) (24,698)
-----------------------------------------------------------------------------
Total Fuel 380,011 424,776 405,163 399,582 395,668
O&M - PPL Operated Plants in PA
Brunner Island 41,500 42,538 43,601 44,691 45,808
Martins Creek 27,000 27,675 28,367 29,076 29,803
Montour 42,000 43,050 44,126 50,075 51,327
Existing CT's 2,450 2,511 2,574 2,638 2,704
Fossil Plant Support Services 22,360 22,919 23,492 24,079 24,681
-----------------------------------------------------------------------------
Total, O&M - PPL Operated Plants in PA 135,310 138,693 142,160 150,560 154,324
O&M - Plants Operated by Others
Conemaugh 10,414 10,537 10,356 10,381 10,688
Keystone 5,559 5,663 5,622 5,587 5,484
Wyman 4 1,186 1,216 1,246 1,277 1,309
-----------------------------------------------------------------------------
Total, O&M - Plants Operated by Others 17,159 17,416 17,223 17,246 17,481
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 532,480 580,885 564,546 567,388 567,473
- ---------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 901,719 992,877 536,659 580,905 629,353
Capital Expenditures 107,197 99,067 87,395 96,153 95,225
Cash Available for Debt Service 794,522 893,811 449,264 484,753 534,128
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Generation (MWh)
Brunner Island 10,560,721 10,560,721 10,560,721 10,560,721 10,560,721
Martins Creek 1,593,960 1,578,812 2,007,714 1,992,853 1,978,133
Montour 10,970,586 10,970,586 10,970,586 10,970,586 10,970,586
CT's -- -- -- -- --
Conemaugh 2,104,163 2,104,163 2,104,163 2,104,163 2,104,163
Keystone 1,597,869 1,597,869 1,597,869 1,597,869 1,597,869
Wyman 4 0 0 0 0 0
- ---------------------------------------------------------------------------------------------------------------------
Total Generation 26,827,299 26,812,152 27,241,054 27,226,193 27,211,473
- ---------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 450,875 460,899 471,154 481,645 492,380
Market Energy Sales 789,584 824,939 882,948 922,078 962,957
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 1,240,459 1,285,837 1,354,101 1,403,723 1,455,337
- ---------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 46.24 47.96 49.71 51.56 53.48
Expenses ($000)
Fuel
Fossil Fuel 389,607 399,133 430,079 440,617 449,188
Other Direct Fossil Fuel Expense 15,274 15,656 16,047 16,448 16,860
NO(x) Emission Reduction Credits (4,430) (5,005) (3,289) (3,767) (4,300)
SO(2) Emission Reduction Credits 31,727 34,738 40,588 44,346 (12,065)
Banked SO(2) Allowances Used -- -- -- -- --
-----------------------------------------------------------------------------
Total Fuel 432,178 444,522 483,426 497,644 449,682
O&M - PPL Operated Plants in PA
Brunner Island 46,953 48,127 49,330 50,564 51,828
Martins Creek 30,548 31,312 32,095 32,897 33,719
Montour 47,519 48,707 55,274 56,656 66,814
Existing CT's 2,772 2,841 2,912 2,985 3,060
Fossil Plant Support Services 25,298 25,931 26,579 27,243 27,925
-----------------------------------------------------------------------------
Total, O&M - PPL Operated Plants in PA 153,091 156,918 166,190 170,345 183,346
O&M - Plants Operated by Others
Conemaugh 10,955 11,229 11,510 11,797 12,092
Keystone 5,621 6,422 6,583 6,054 6,205
Wyman 4 1,342 1,375 1,410 1,445 1,481
-----------------------------------------------------------------------------
Total, O&M - Plants Operated by Others 17,918 19,026 19,502 19,296 19,778
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 603,187 620,467 669,118 687,285 652,806
- ---------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 637,272 665,371 684,983 716,439 802,531
Capital Expenditures 60,410 61,042 106,478 151,621 107,142
Cash Available for Debt Service 576,862 604,329 578,505 564,818 695,389
A-93
PPL Existing Fossil Units
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Generation (MWh)
Brunner Island 10,272,047 9,999,560 9,742,351 9,499,564 9,270,390
Martins Creek 1,859,005 1,749,126 1,203,873 1,110,395 1,024,176
Montour 10,970,586 10,970,586 10,970,586 10,970,586 10,970,586
CT's -- -- -- -- --
Conemaugh 2,104,163 2,104,163 2,104,163 2,104,163 2,104,163
Keystone 1,597,869 1,597,869 1,597,869 1,597,869 1,597,869
Wyman 4 0 0 0 0 0
- -----------------------------------------------------------------------------------------------------------------
Total Generation 26,803,671 26,421,304 25,618,842 25,282,578 24,967,185
- -----------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 499,816 507,365 515,028 522,807 530,705
Market Energy Sales 968,394 974,436 957,241 963,873 971,071
- -----------------------------------------------------------------------------------------------------------------
Total Revenues 1,468,211 1,481,801 1,472,269 1,486,680 1,501,776
- -----------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 54.78 56.08 57.47 58.80 60.15
Expenses ($000)
Fuel
Fossil Fuel 449,558 450,296 427,422 428,260 429,416
Other Direct Fossil Fuel Expense 17,281 17,713 18,156 18,610 19,075
NO(x) Emission Reduction Credits (7,189) (10,135) (15,648) (18,977) (22,438)
SO(2) Emission Reduction Credits (15,534) (19,472) (28,653) (34,537) (41,446)
Banked SO(2) Allowances Used -- -- -- -- --
--------------------------------------------------------------------------
Total Fuel 444,117 438,401 401,276 393,356 384,608
O&M - PPL Operated Plants in PA
Brunner Island 53,124 54,452 55,813 57,208 58,638
Martins Creek 34,562 35,426 36,312 37,220 38,150
Montour 68,485 76,101 78,004 73,750 75,594
Existing CT's 3,136 3,215 3,295 3,377 3,462
Fossil Plant Support Services 28,623 29,338 30,072 30,824 31,594
--------------------------------------------------------------------------
Total, O&M - PPL Operated Plants in PA 187,929 198,532 203,495 202,379 207,439
O&M - Plants Operated by Others
Conemaugh 12,395 12,704 13,022 13,348 13,681
Keystone 7,089 7,266 6,682 6,849 7,825
Wyman 4 1,518 1,556 1,595 1,635 1,676
--------------------------------------------------------------------------
Total, O&M - Plants Operated by Others 21,001 21,526 21,299 21,832 23,182
- -----------------------------------------------------------------------------------------------------------------
Total Expenses 653,048 658,460 626,071 617,567 615,228
- -----------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 815,163 823,341 846,198 869,113 886,548
Capital Expenditures 51,012 52,287 53,594 54,934 56,308
Cash Available for Debt Service 764,151 771,054 792,604 814,178 830,241
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Generation (MWh)
Brunner Island 9,250,849 9,231,406 9,212,063 9,192,817 9,173,669
Martins Creek 1,080,523 1,139,970 1,202,688 1,268,857 1,338,665
Montour 10,970,586 10,970,586 10,970,586 10,970,586 10,970,586
CT's -- -- -- -- --
Conemaugh 2,104,163 2,104,163 2,104,163 2,104,163 2,104,163
Keystone 1,597,869 1,597,869 1,597,869 1,597,869 1,597,869
Wyman 4 0 0 0 0 0
- ----------------------------------------------------------------------------------------------------------------
Total Generation 25,003,991 25,043,996 25,087,370 25,134,292 25,184,953
- ----------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 536,669 542,700 548,799 554,966 561,203
Market Energy Sales 993,158 1,015,843 1,039,146 1,063,092 1,087,704
- ----------------------------------------------------------------------------------------------------------------
Total Revenues 1,529,827 1,558,542 1,587,945 1,618,058 1,648,907
- ----------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 61.18 62.23 63.30 64.38 65.47
Expenses ($000)
Fuel
Fossil Fuel 437,708 446,230 454,993 464,008 473,287
Other Direct Fossil Fuel Expense 19,552 20,041 20,542 21,055 21,582
NO(x) Emission Reduction Credits (23,089) (23,754) (24,431) (25,121) (25,824)
S0(2) Emission Reduction Credits (41,840) (42,185) (42,476) (42,705) (42,866)
Banked S0(2) Allowances Used -- -- -- -- --
-------------------------------------------------------------------------
Total Fuel 392,331 400,332 408,628 417,237 426,179
O&M - PPL Operated Plants in PA
Brunner Island 60,104 61,607 63,147 64,726 66,344
Martins Creek 39,104 40,082 41,084 42,111 43,164
Montour 84,001 86,101 81,407 83,442 92,722
Existing CT's 3,548 3,637 3,728 3,821 3,917
Fossil Plant Support Services 32,384 33,194 34,023 34,874 35,746
-------------------------------------------------------------------------
Total, O&M - PPL Operated Plants in PA 219,142 224,621 223,389 228,973 241,892
O&M - Plants Operated by Others
Conemaugh 14,023 14,374 14,733 15,102 15,479
Keystone 8,020 7,376 7,560 8,637 8,853
Wyman 4 1,718 1,761 1,805 1,850 1,896
-------------------------------------------------------------------------
Total, O&M - Plants Operated by Others 23,761 23,510 24,098 25,588 26,228
- ----------------------------------------------------------------------------------------------------------------
Total Expenses 635,234 648,463 656,115 671,799 694,298
- ----------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 894,593 910,079 931,830 946,259 954,609
Capital Expenditures 57,715 59,158 60,637 62,153 63,707
Cash Available for Debt Service 836,878 850,921 871,193 884,106 890,902
A-94
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Cash Flow Summary for Projects Under Development
A-95
PPL Projects Under Development
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Percent Of Year of Operations 100% 100% 100% 100% 100%
Year of Operation 1.0 2.0 3.0 4.0 5.0
- ---------------------------------------------------------------------------------------------------------------------
Generation (MWh)
Griffith 993,189 1,543,218 1,735,353 1,642,245 1,532,347
Wallingford 67,753 181,642 342,359 403,666 464,972
Kings Park -- -- 771,552 664,271 556,990
Lower Mt Bethel -- -- -- 2,303,394 2,666,648
PA New CTs -- -- 530,264 647,582 764,899
Sundance -- 495,081 613,306 416,737 393,742
University Park -- 216,567 435,751 461,060 486,369
Starbuck -- -- -- -- 9,645,319
- ---------------------------------------------------------------------------------------------------------------------
Total 1,060,942 2,436,507 4,428,585 6,538,954 16,511,287
- ---------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 35,212 160,120 220,644 218,368 340,748
Market Energy Sales 89,359 155,452 202,708 261,597 557,710
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 124,571 315,572 423,352 479,965 898,458
- ---------------------------------------------------------------------------------------------------------------------
All-In Revenues ($/MWh) 117.42 129.52 95.60 73.40 54.41
Expenses ($000)
Fuel
Griffith 39,643 45,776 45,259 40,091 34,362
Wallingford 4,044 8,477 13,940 15,850 17,537
Kings Park -- -- 30,525 25,563 20,789
Lower Mt Bethel -- -- -- 57,772 63,595
PA New CT's -- -- 19,990 23,577 26,795
Sundance -- 20,044 21,768 13,816 11,967
University Park -- 8,519 15,261 15,492 15,606
Starbuck -- -- -- -- 205,837
-----------------------------------------------------------------------------
Total, Fuel 43,687 82,817 146,743 192,162 396,488
O&M
Griffith 5,759 12,335 13,072 21,692 13,595
Wallingford 3,128 4,463 4,691 4,903 4,994
Kings Park -- -- 7,738 7,906 7,803
Lower Mt Bethel -- -- -- 8,134 8,660
PA New CT's -- -- 5,528 6,405 6,759
Sundance -- 7,924 18,282 14,607 15,836
University Park -- 3,009 5,573 6,068 6,261
Starbuck -- -- -- -- 43,554
-----------------------------------------------------------------------------
Total, O&M 8,886 27,731 54,884 69,715 107,463
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 52,573 110,548 201,627 261,877 503,951
- ---------------------------------------------------------------------------------------------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Percent Of Year of Operations 100% 100% 100% 100% 100%
Year of Operation 6.0 7.0 8.0 9.0 10.0
- ------------------------------------------------------------------------------------------------------------------
Generation (MWh)
Griffith 1,559,863 1,587,892 1,616,445 1,645,534 1,675,167
Wallingford 440,232 416,809 394,631 373,634 353,754
Kings Park 511,603 469,914 431,622 396,450 364,144
Lower Mt Bethel 2,732,089 2,799,452 2,868,819 2,940,274 3,013,910
PA New CTs 777,440 790,329 803,582 817,212 831,234
Sundance 396,870 400,023 403,202 406,405 409,634
University Park 546,167 613,317 688,723 773,400 868,488
Starbuck 9,443,070 9,245,062 9,051,207 8,861,416 8,675,605
- ------------------------------------------------------------------------------------------------------------------
Total 16,407,334 16,322,799 16,258,231 16,214,325 16,191,937
- ------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 351,577 362,871 374,653 386,944 399,429
Market Energy Sales 571,851 587,087 603,513 621,241 640,392
- ------------------------------------------------------------------------------------------------------------------
Total Revenues 923,428 949,958 978,166 1,008,185 1,039,821
- ------------------------------------------------------------------------------------------------------------------
All-In Revenues ($/MWh) 56.28 58.20 60.16 62.18 64.22
Expenses ($000)
Fuel
Griffith 36,094 37,913 39,824 41,832 43,942
Wallingford 17,186 16,842 16,505 16,175 15,851
Kings Park 19,800 18,857 17,960 17,105 16,291
Lower Mt Bethel 67,417 71,480 75,799 80,394 85,282
PA New CT's 28,164 29,609 31,134 32,744 34,443
Sundance 12,452 12,957 13,483 14,030 14,599
University Park 18,091 20,970 24,308 28,178 32,663
Starbuck 208,262 210,716 213,199 215,711 218,253
--------------------------------------------------------------------------
Total, Fuel 407,466 419,345 432,213 446,169 461,325
O&M
Griffith 14,064 23,189 14,217 14,328 24,199
Wallingford 4,947 4,901 10,222 10,316 4,628
Kings Park 7,797 7,796 14,235 14,403 7,635
Lower Mt Bethel 10,832 11,043 22,628 11,657 13,053
PA New CT's 7,335 7,537 7,330 7,947 8,172
Sundance 16,858 17,171 17,219 17,540 17,580
University Park 6,187 6,788 22,737 7,057 7,777
Starbuck 44,400 45,264 46,149 47,050 47,971
--------------------------------------------------------------------------
Total, O&M 112,421 123,690 154,738 130,298 131,015
- ------------------------------------------------------------------------------------------------------------------
Total Expenses 519,886 543,035 586,951 576,466 592,339
- ------------------------------------------------------------------------------------------------------------------
A-96
PPL Projects Under Development
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Operating Cash Flow ($000) 71,998 205,024 221,725 218,087 394,508
Other Income/(Expenses) -- -- -- -- --
Capital Expenditures 53,496 -- -- -- --
Lease Payments for New Peakers -- 26,488 76,669 91,198 91,198
Lease Payments for LMB -- -- -- 35,822 35,464
Cash Available for Debt Service 18,502 178,536 145,056 91,067 267,845
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Operating Cash Flow ($000) 403,542 406,923 391,215 431,719 447,482
Other Income/(Expenses) -- -- -- -- --
Capital Expenditures -- -- -- -- --
Lease Payments for New Peakers 91,198 91,198 91,198 91,198 91,198
Lease Payments for LMB 35,109 34,758 34,411 34,066 33,726
Cash Available for Debt Service 277,234 280,966 265,606 306,454 322,557
A-97
PPL Projects Under Development
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Percent Of Year of Operations 100% 100% 100% 100% 100%
Year of Operation 11.0 12.0 13.0 14.0 15.0
- --------------------------------------------------------------------------------------------------------------------
Generation (MWh)
Griffith 1,702,248 1,730,281 1,759,335 1,789,486 1,820,815
Wallingford 344,764 336,002 327,463 319,141 311,031
Kings Park 367,686 371,261 374,872 378,518 382,199
Lower Mt Bethel 2,951,702 2,892,781 2,836,761 2,783,308 2,732,137
PA New CT's 817,212 803,582 790,329 777,440 764,899
Sundance 484,187 572,307 676,466 799,581 945,103
University Park 946,476 1,031,466 1,124,089 1,225,028 1,335,032
Starbuck 8,348,485 8,033,700 7,730,784 7,439,290 7,158,786
- --------------------------------------------------------------------------------------------------------------------
Total 15,962,760 15,771,382 15,620,099 15,511,791 15,450,001
- --------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 405,934 412,560 419,312 426,190 432,976
Market Energy Sales 641,376 643,758 647,665 653,248 660,683
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 1,047,310 1,056,319 1,066,977 1,079,438 1,093,658
- --------------------------------------------------------------------------------------------------------------------
All-In Revenues ($/MWh) 65.61 66.98 68.31 69.59 70.79
Expenses ($000)
Fuel
Griffith 44,560 45,199 45,861 46,549 47,264
Wallingford 15,925 15,999 16,073 16,147 16,222
Kings Park 17,098 17,945 18,833 19,765 20,744
Lower Mt Bethel 85,735 86,269 86,877 87,551 88,286
PA New CT's 35,043 35,660 36,295 36,947 37,619
Sundance 17,177 20,211 23,781 27,982 32,924
University Park 36,219 40,161 44,533 49,380 54,755
Starbuck 209,908 201,882 194,162 186,738 179,598
--------------------------------------------------------------------------------
Total, Fuel 461,664 463,325 466,415 471,060 477,412
O&M
Griffith 14,868 15,311 26,139 15,904 15,965
Wallingford 4,764 10,510 4,738 4,728 4,547
Kings Park 7,896 14,889 7,863 8,145 8,233
Lower Mt Bethel 9,772 36,592 14,601 13,250 20,039
PA New CT's 7,912 24,212 25,709 26,325 8,622
Sundance 17,452 35,657 30,533 18,363 18,975
University Park 8,121 29,613 23,455 9,321 9,788
Starbuck 48,912 49,875 50,857 51,860 52,885
--------------------------------------------------------------------------------
Total, O&M 119,698 216,658 183,895 147,896 139,055
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 581,362 679,983 650,310 618,956 616,468
- --------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Percent Of Year of Operations 100% 100% 100% 100% 100%
Year of Operation 16.0 17.0 18.0 19.0 20.0
- ---------------------------------------------------------------------------------------------------------------------
Generation (MWh)
Griffith 1,825,893 1,831,168 1,836,649 1,842,342 1,848,257
Wallingford 286,859 264,567 244,006 225,044 207,555
Kings Park 358,047 335,422 314,226 294,370 275,769
Lower Mt Bethel 2,677,852 2,624,668 2,572,565 2,521,519 2,471,509
PA New CT's 738,903 713,791 689,532 666,098 643,460
Sundance 972,540 1,000,775 1,029,829 1,059,726 1,090,492
University Park 1,266,211 1,200,939 1,139,031 1,080,314 1,024,624
Starbuck 7,136,052 7,113,389 7,090,799 7,068,280 7,045,833
- ---------------------------------------------------------------------------------------------------------------------
Total 15,262,358 15,084,719 14,916,637 14,757,694 14,607,499
- ---------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Market Capacity Sales 438,798 444,706 450,702 456,787 403,810
Market Energy Sales 654,189 647,985 642,066 636,428 631,067
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 1,092,986 1,092,690 1,092,768 1,093,215 1,034,877
- ---------------------------------------------------------------------------------------------------------------------
All-In Revenues ($/MWh) 71.61 72.44 73.26 74.08 70.85
Expenses ($000)
Fuel
Griffith 47,947 48,645 49,358 50,087 50,832
Wallingford 15,371 14,565 13,801 13,077 12,392
Kings Park 19,973 19,230 18,515 17,827 17,164
Lower Mt Bethel 89,336 90,399 91,476 92,567 93,673
PA New CT's 37,364 37,112 36,861 36,612 36,364
Sundance 34,308 35,751 37,254 38,821 40,453
University Park 52,947 51,197 49,506 47,870 46,289
Starbuck 176,432 173,323 170,268 167,266 164,318
---------------------------------------------------------------------------------
Total, Fuel 473,679 470,222 467,039 464,128 461,485
O&M
Griffith 27,321 16,210 16,316 16,507 29,186
Wallingford 18,310 18,709 4,646 4,899 4,970
Kings Park 8,051 25,023 25,477 8,141 8,410
Lower Mt Bethel 13,797 14,990 11,371 46,982 14,313
PA New CT's 7,792 9,452 12,231 9,286 9,464
Sundance 19,020 19,112 19,187 48,729 49,953
University Park 9,883 9,984 44,385 82,789 10,329
Starbuck 53,934 55,004 56,097 57,214 58,357
---------------------------------------------------------------------------------
Total, O&M 158,109 168,485 189,710 274,547 184,983
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 631,787 638,707 656,749 738,675 646,468
- ---------------------------------------------------------------------------------------------------------------------
A-98
PPL Projects Under Development
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Operating Cash Flow ($000) 465,948 376,335 416,667 460,481 477,191
Other Income/(Expenses) -- -- -- -- --
Capital Expenditures -- -- -- -- --
Lease Payments for New Peakers 91,198 91,198 91,198 91,198 91,198
Lease Payments for LMB 33,389 33,055 32,724 32,397 32,073
Cash Available for Debt Service 341,361 252,082 292,745 336,886 353,919
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Operating Cash Flow ($000) 461,199 453,984 436,018 354,540 388,409
Other Income/(Expenses) -- -- -- -- --
Capital Expenditures -- -- -- -- --
Lease Payments for New Peakers 91,198 91,198 91,198 91,198 91,198
Lease Payments for LMB 31,752 31,435 31,120 30,809 30,501
Cash Available for Debt Service 338,248 331,351 313,700 232,532 266,710
A-99
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Cash Flow Summary for Nuclear Generating Assets
A-100
PPL Nuclear Assets
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Generation (MWh) 15,279,643 15,384,107 15,651,071 15,999,286 16,115,357
Revenues ($000)
Net Market Capacity Sales 212,674 280,327 131,432 146,025 159,341
Net Market Energy Sales 462,526 434,925 428,964 442,029 450,038
Capacity Reservation Charge 23,666 21,969 20,696 19,422 18,149
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 698,866 737,221 581,092 607,476 627,528
- --------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 45.74 47.92 37.13 37.97 38.94
Expenses ($000)
Susquehanna Fuel (Non-Capital) 16,883 17,044 17,360 17,753 17,930
Susquehanna O&M 195,472 202,529 208,807 197,949 202,898
Nuclear Decommissioning Expense 23,666 21,969 20,696 19,422 18,149
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 236,021 241,542 246,863 235,124 238,977
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 462,844 495,679 334,229 372,351 388,551
Other Income (Expenses) 17,767 18,408 18,979 17,992 18,442
Capital Expenditures
Capital Projects 37,710 49,500 67,500 48,600 35,100
Nuclear Fuel 55,803 55,306 54,788 56,158 57,562
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 93,513 104,806 122,288 104,758 92,662
- --------------------------------------------------------------------------------------------------------------------
Cash Available for Debt Service 387,099 409,282 230,920 285,585 314,331
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Generation (MWh) 16,115,357 16,115,357 16,115,357 16,115,357 16,115,357
Revenues ($000)
Net Market Capacity Sales 162,819 166,373 170,004 173,715 177,507
Net Market Energy Sales 469,935 490,711 512,406 535,060 558,716
Capacity Reservation Charge 16,875 15,602 14,328 13,055 --
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 649,629 672,686 696,739 721,830 736,222
- --------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 40.31 41.74 43.23 44.79 45.68
Expenses ($000)
Susquehanna Fuel (Non-Capital) 18,000 18,071 18,144 18,219 18,296
Susquehanna O&M 207,971 213,170 218,499 223,961 229,561
Nuclear Decommissioning Expense 16,875 15,602 14,328 13,055 --
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 242,845 246,843 250,971 255,235 247,856
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 406,784 425,844 445,768 466,595 488,366
Other Income (Expenses) 18,903 19,376 19,860 20,356 20,865
Capital Expenditures
Capital Projects 18,329 18,787 19,257 19,738 20,232
Nuclear Fuel 59,001 60,476 61,988 63,538 65,126
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 77,330 79,263 81,245 83,276 85,358
- --------------------------------------------------------------------------------------------------------------------
Cash Available for Debt Service 348,357 365,956 384,383 403,675 423,874
A-101
PPL Nuclear Assets
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Generation (MWh) 16,115,357 16,115,357 16,115,357 16,115,357 16,115,357
Revenues ($000)
Net Market Capacity Sales 180,206 182,946 185,727 188,551 191,418
Net Market Energy Sales 569,403 580,294 591,394 602,705 614,234
Capacity Reservation Charge -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 749,608 763,240 777,121 791,257 805,652
- --------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 46.52 47.36 48.22 49.10 49.99
Expenses ($000)
Susquehanna Fuel (Non-Capital) 18,374 18,455 18,538 18,622 18,709
Susquehanna O&M 235,300 241,182 247,212 253,392 259,727
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 253,674 259,637 265,749 272,014 278,436
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 495,935 503,603 511,372 519,243 527,216
Other Income (Expenses) 21,387 21,922 22,470 23,031 23,607
Capital Expenditures
Capital Projects 20,737 21,256 21,787 22,332 22,890
Nuclear Fuel 66,754 68,423 70,134 71,887 73,684
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 87,492 89,679 91,921 94,219 96,574
- --------------------------------------------------------------------------------------------------------------------
Cash Available for Debt Service 429,830 435,845 441,921 448,055 454,249
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Generation (MWh) 16,115,357 16,115,357 16,115,357 16,115,357 16,115,357
Revenues ($000)
Net Market Capacity Sales 193,560 195,726 197,917 200,131 202,371
Net Market Energy Sales 627,362 640,771 654,466 668,454 682,742
Capacity Reservation Charge -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 820,922 836,497 852,383 868,586 885,112
- --------------------------------------------------------------------------------------------------------------------
All-In Revenue ($/MWh) 50.94 51.91 52.89 53.90 54.92
Expenses ($000)
Susquehanna Fuel (Non-Capital) 18,798 18,889 18,983 19,079 19,177
Susquehanna O&M 266,220 272,875 279,697 286,690 293,857
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 285,018 291,765 298,680 305,768 313,034
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 535,904 544,732 553,703 562,817 572,078
Other Income (Expenses) 24,197 24,802 25,422 26,058 26,709
Capital Expenditures
Capital Projects 23,462 24,049 24,650 25,266 25,898
Nuclear Fuel 75,526 77,415 79,350 81,334 83,367
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 98,989 101,464 104,000 106,600 109,265
- --------------------------------------------------------------------------------------------------------------------
Cash Available for Debt Service 461,113 468,071 475,125 482,275 489,523
A-102
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Cash Flow Summary for Hydroelectric Generating Assets (Non-Montana)
A-103
PPL Hydroelectric Assets
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Generation (MWh)
Holtwood 574,526 574,526 574,526 574,526 574,526
Wallenpaupack 77,865 77,865 77,865 77,865 77,865
Safe Harbor 355,566 355,566 355,566 355,566 355,566
Maine Hydro 250,987 250,987 250,987 250,987 250,987
- --------------------------------------------------------------------------------------------------------------------
Total Generation 1,258,944 1,258,944 1,258,944 1,258,944 1,258,944
- --------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Net Market Capacity Sales 37,835 46,770 21,564 23,301 25,112
Net Market Energy Sales 44,395 40,848 39,024 39,254 39,471
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 82,230 87,618 60,588 62,555 64,583
- --------------------------------------------------------------------------------------------------------------------
All-In Revenues 65.32 69.60 48.13 49.69 51.30
Expenses ($000)
Holtwood O&M 3,640 3,731 3,824 3,920 4,018
Wallenpaupack O&M 2,310 2,368 2,427 2,488 2,550
Safe Harbor O&M 3,330 3,413 3,499 3,586 3,676
Maine Hydro O&M 5,100 5,228 5,358 5,492 5,629
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 14,380 14,740 15,108 15,486 15,873
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 67,850 72,878 45,480 47,069 48,710
Capital Expenditures 7,704 4,462 9,017 6,372 3,817
Cash Available for Debt Service 60,146 68,416 36,462 40,697 44,893
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Generation (MWh)
Holtwood 574,526 574,526 574,526 574,526 574,526
Wallenpaupack 77,865 77,865 77,865 77,865 77,865
Safe Harbor 355,566 355,566 355,566 355,566 355,566
Maine Hydro 250,987 250,987 250,987 250,987 250,987
- --------------------------------------------------------------------------------------------------------------------
Total Generation 1,258,944 1,258,944 1,258,944 1,258,944 1,258,944
- --------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Net Market Capacity Sales 25,811 26,535 27,286 28,064 28,873
Net Market Energy Sales 41,095 42,787 44,550 46,388 48,304
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 66,905 69,321 71,836 74,453 77,177
- --------------------------------------------------------------------------------------------------------------------
All-In Revenues 53.14 55.06 57.06 59.14 61.30
Expenses ($000)
Holtwood O&M 4,118 4,221 4,327 4,435 4,546
Wallenpaupack O&M 2,614 2,679 2,746 2,815 2,885
Safe Harbor O&M 3,768 3,862 3,958 4,057 4,159
Maine Hydro O&M 5,770 5,914 6,062 6,214 6,369
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 16,270 16,676 17,093 17,521 17,959
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 50,635 52,645 54,743 56,932 59,218
Capital Expenditures 1,352 1,379 1,407 1,436 1,466
Cash Available for Debt Service 49,284 51,266 53,335 55,496 57,753
A-104
PPL Hydroelectric Assets
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Generation (MWh)
Holtwood 574,526 574,526 574,526 574,526 574,526
Wallenpaupack 77,865 77,865 77,865 77,865 77,865
Safe Harbor 355,566 355,566 355,566 355,566 355,566
Maine Hydro 250,987 250,987 250,987 250,987 250,987
- --------------------------------------------------------------------------------------------------------------------
Total Generation 1,258,944 1,258,944 1,258,944 1,258,944 1,258,944
- --------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Net Market Capacity Sales 29,267 29,667 30,073 30,484 30,902
Net Market Energy Sales 49,214 50,142 51,087 52,050 53,032
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 78,481 79,808 81,159 82,534 83,934
- --------------------------------------------------------------------------------------------------------------------
All-In Revenues 62.34 63.39 64.47 65.56 66.67
Expenses ($000)
Holtwood O&M 4,660 4,776 4,895 5,018 5,143
Wallenpaupack O&M 2,957 3,031 3,107 3,184 3,264
Safe Harbor O&M 4,263 4,369 4,478 4,590 4,705
Maine Hydro O&M 6,528 6,692 6,859 7,030 7,206
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 18,408 18,868 19,340 19,823 20,319
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 60,074 60,941 61,820 62,711 63,615
Capital Expenditures 1,502 1,540 1,578 1,618 1,658
Cash Available for Debt Service 58,571 59,401 60,242 61,094 61,957
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Generation (MWh)
Holtwood 574,526 574,526 574,526 574,526 574,526
Wallenpaupack 77,865 77,865 77,865 77,865 77,865
Safe Harbor 355,566 355,566 355,566 355,566 355,566
Maine Hydro 250,987 250,987 250,987 250,987 250,987
- --------------------------------------------------------------------------------------------------------------------
Total Generation 1,258,944 1,258,944 1,258,944 1,258,944 1,258,944
- --------------------------------------------------------------------------------------------------------------------
Revenues ($000)
Net Market Capacity Sales 31 270 31,643 32,020 32,401 32,787
Net Market Energy Sales 54,049 55,087 56,145 57,223 58,323
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 85,319 86,729 88,164 89,624 91,110
- --------------------------------------------------------------------------------------------------------------------
All-In Revenues 67.77 68.89 70.03 71.19 72.37
Expenses ($000)
Holtwood O&M 5,272 5,404 5,539 5,677 5,819
Wallenpaupack O&M 3,346 3,429 3,515 3,603 3,693
Safe Harbor O&M 4,823 4,943 5,067 5,194 5,324
Maine Hydro O&M 7,386 7,571 7,760 7,954 8,153
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 20,827 21,347 21,881 22,428 22,989
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 64,493 65,382 66,283 67,196 68,122
Capital Expenditures 1,700 1,742 1,786 1,830 1,876
Cash Available for Debt Service 62,793 63,640 64,498 65,366 66,245
A-105
Exhibit I Independent Technical Review
Financial Projections -- Base Case PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Cash Flow Summary for Montana Generating Assets
A-106
PPL Montana Units
Base Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Generation (MWh) 7,422,967 8,332,838 8,332,838 8,414,353 8,728,767
Revenues ($000)
Market Capacity Sales 131,396 200,700 79,851 65,918 86,882
Market Energy Sales 458,929 372,957 301,747 270,455 274,992
Other 2,899 3,200 3,200 3,200 3,800
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 593,224 576,857 384,798 339,573 365,674
- ---------------------------------------------------------------------------------------------------------------------
Expenses ($000)
Fuel
Fossil Fuel 41,561 41,029 39,572 38,002 38,465
Emission Allowances (258) (282) (309) (338) (369)
----------------------------------------------------------------------------
Total Fuel 41,303 40,747 39,263 37,664 38,096
O&M
Colstrip 17,600 18,040 18,491 18,953 19,427
Corette 4,967 5,091 5,638 5,393 5,526
Montana Hydro 7,740 7,750 7,940 8,140 8,344
----------------------------------------------------------------------------
Total O&M 30,307 30,881 32,069 32,486 33,297
Other
Colstrip 3,455 3,523 3,592 3,663 3,735
Corette 456 468 479 491 504
Montana Hydro 17,670 18,132 18,596 19,039 19,535
----------------------------------------------------------------------------
Total Other 21,581 22,123 22,667 23,193 23,774
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 93,191 93,751 93,999 93,343 95,167
- ---------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 500,033 483,106 290,800 246,230 270,508
Non-Income Taxes 17,079 17,303 17,754 18,180 18,659
Capital Expenditures 23,472 50,409 48,248 48,457 56,970
Montana Debt Service 36,127 48,338 46,110 42,744 37,490
Cash Available for Debt Service 423,355 367,056 178,688 136,849 157,388
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Generation (MWh) 8,941,441 9,003,343 9,003,343 9,003,343 9,003,343
Revenues ($000)
Market Capacity Sales 92,105 95,784 98,846 102,007 105,268
Market Energy Sales 292,783 305,311 315,739 326,524 337,678
Other 4,400 5,700 6,000 6,000 6,000
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 389,287 406,794 420,585 434,531 448,946
- --------------------------------------------------------------------------------------------------------------------
Expenses ($000)
Fuel
Fossil Fuel 38,870 39,280 39,694 40,113 40,537
Emission Allowances (403) (441) (481) (527) (575)
---------------------------------------------------------------------------
Total Fuel 38,467 38,839 39,213 39,586 39,962
O&M
Colstrip 19,913 20,411 20,921 21,444 21,980
Corette 6,024 5,779 5,922 6,529 6,243
Montana Hydro 8,552 8,766 8,985 9,210 9,440
---------------------------------------------------------------------------
Total O&M 34,489 34,955 35,828 37,183 37,663
Other
Colstrip 3,809 3,884 3,961 4,039 4,121
Corette 516 529 542 556 570
Montana Hydro 20,031 20,540 21,060 21,568 22,112
---------------------------------------------------------------------------
Total Other 24,356 24,953 25,563 26,163 26,803
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 97,312 98,748 100,604 102,932 104,428
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 291,975 308,047 319,981 331,599 344,518
Non-Income Taxes 19,103 19,596 20,066 20,591 21,120
Capital Expenditures 19,048 13,663 13,456 13,710 14,085
Montana Debt Service 37,283 35,219 37,209 38,847 40,501
Cash Available for Debt Service 216,541 239,569 249,249 258,451 268,812
A-107
PPL Montana Units
Base Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Generation (MWh) 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Revenues ($000)
Market Capacity Sales 112,522 120,276 128,563 137,422 146,892
Market Energy Sales 340,873 344,308 348,001 351,968 356,228
Other 6,000 6,000 6,000 6,000 3,000
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues 459,395 470,584 482,564 495,390 506,120
- ---------------------------------------------------------------------------------------------------------------------
Expenses ($000)
Fuel
Fossil Fuel 40,997 41,462 41,934 42,411 42,893
Emission Allowances (591) (604) (620) (635) (651)
------------------------------------------------------------------------------
Total Fuel 40,406 40,858 41,314 41,776 42,242
O&M
Colstrip 22,529 23,093 23,670 24,262 24,868
Corette 6,401 7,031 6,724 6,892 7,572
Montana Hydro 9,676 9,918 10,166 10,420 10,680
------------------------------------------------------------------------------
Total O&M 38,606 40,042 40,560 41,574 43,121
Other
Colstrip 4,202 4,286 4,372 4,460 4,551
Corette 584 599 614 629 645
Montana Hydro 22,670 23,240 23,826 24,423 25,030
------------------------------------------------------------------------------
Total Other 27,456 28,125 28,812 29,512 30,226
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses 106,468 109,025 110,685 112,861 115,589
- ---------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 352,927 361,559 371,879 382,529 390,530
Non-Income Taxes 21,624 22,178 22,744 23,285 23,214
Capital Expenditures 14,463 19,351 18,112 18,565 21,202
Montana Debt Service 40,922 41,406 44,330 45,820 39,783
Cash Available for Debt Service 275,918 278,624 286,693 294,859 306,331
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Generation (MWh) 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Revenues ($000)
Market Capacity Sales 148,900 150,936 152,999 155,091 157,211
Market Energy Sales 352,796 349,445 346,174 342,982 339,868
Other -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Revenues 501,696 500,380 499,173 498,072 497,079
- --------------------------------------------------------------------------------------------------------------------
Expenses ($000)
Fuel
Fossil Fuel 43,397 43,908 44,425 44,948 45,478
Emission Allowances (667) (685) (701) (718) (736)
-----------------------------------------------------------------------------
Total Fuel 42,730 43,223 43,724 44,230 44,742
O&M
Colstrip 25,490 26,127 26,780 27,450 28,136
Corette 7,241 7,567 8,454 8,264 8,471
Montana Hydro 10,947 11,221 11,502 11,789 12,084
-----------------------------------------------------------------------------
Total O&M 43,678 44,915 46,736 47,503 48,691
Other
Colstrip 4,642 4,734 4,831 4,928 5,051
Corette 661 677 694 712 730
Montana Hydro 25,653 26,293 26,951 27,624 28,315
-----------------------------------------------------------------------------
Total Other 30,956 31,704 32,476 33,264 34,096
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 117,365 119,842 122,936 124,997 127,529
- --------------------------------------------------------------------------------------------------------------------
Operating Cash Flow ($000) 384,331 380,538 376,237 373,075 369,550
Non-Income Taxes 23,123 23,701 24,293 24,899 25,522
Capital Expenditures 19,505 19,993 20,492 21,004 21,529
Montana Debt Service 15,292 3,935 3,668 3,401 3,134
Cash Available for Debt Service 326,411 332,909 327,784 323,771 319,366
A-108
Exhibit II Independent Technical Review
Financial Projections -- Sensitivity Cases PPL Energy Supply LLC
- --------------------------------------------------------------------------------
EXHIBIT II
SENSITIVITY CASES
High Case Consolidated Cash Flow Summary
Low Case Consolidated Cash Flow Summary
A-109
Exhibit II Independent Technical Review
Financial Projections -- Sensitivity Cases PPL Energy Supply LLC
- --------------------------------------------------------------------------------
High Case Consolidated Cash Flow Summary
A-110
PPL Consolidation
High Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects -- 630 630 1,232 1,232
Pennsylvania Nuclear 1,975 1,988 2,023 2,068 2,083
Other New Projects 248 1,215 1,755 1,755 2,955
Montana Fossil and Hydro 1,208 1,208 1,208 1,221 1,273
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 9,038 10,649 11,223 11,883 13,150
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,901,259 27,024,155 26,433,657 26,709,155 26,984,653
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects -- -- 374,349 2,306,840 2,892,496
Pennsylvania Nuclear 15,276,535 15,376,339 15,631,391 15,964,068 16,074,961
Other New Projects 982,678 2,715,529 4,188,813 3,099,391 10,006,115
Montana Fossil and Hydro 7,422,967 8,332,838 8,332,838 8,414,353 8,728,767
Montana Purchases - Basin 364,090 364,090 364,090 364,090 148,608
Maine 448,445 250,987 250,987 250,987 250,987
NUG Contracts 2,537,187 2,537,187 2,537,187 2,537,187 2,537,187
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 54,941,119 57,609,082 59,121,269 60,654,028 68,631,732
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 31,043,565 30,375,744 31,110,038 32,206,476 33,677,785
Other Contract Sales 3,485,801 3,303,729 3,283,033 1,156,654 --
Net Market Sales (Purchases) 10,422,474 13,083,397 13,831,290 16,255,885 23,719,127
Montana Market Sales 2,573,057 4,180,472 4,569,216 4,650,731 4,749,663
Montana Contract Sales 5,214,000 4,516,456 4,127,712 4,127,712 4,127,712
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 52,738,897 55,459,798 56,921,288 58,397,458 66,274,287
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 306,163 573,406 431,714 445,926 464,618
Merchant Energy Sales 297,283 399,523 426,222 520,502 788,264
Contract Capacity Sales (Purchases) 54,000 63,000 66,600 30,900 --
Contract Energy Sales (Purchases) 1,131,869 1,201,237 1,157,977 1,185,828 1,266,291
Montana Merchant Revenues 249,322 381,601 267,453 267,482 197,526
Montana Contract Revenues 101,985 121,241 147,805 146,748 155,882
Trading -- -- -- -- --
Other 26,565 25,169 23,896 22,622 21,949
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,167,187 2,765,177 2,521,667 2,620,007 2,894,530
- --------------------------------------------------------------------------------------------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,307 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,184 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,948,858 26,913,249 26,877,826 26,842,588 26,807,533
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 2,872,958 2,854,060 2,835,747 2,817,972 2,800,691
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 9,399,970 8,861,647 8,381,768 7,953,546 7,572,134
Montana Fossil and Hydro 8,941,441 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin 148,608 148,608 148,608 148,608 99,072
Maine 250,987 250,987 250,987 250,987 250,987
NUG Contracts 2,537,187 2,537,187 1,772,806 1,268,608 95,335
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 68,182,927 67,651,999 66,354,003 65,368,570 63,712,014
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 34,404,881 35,125,621 35,826,477 36,539,915 --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 22,279,655 20,915,633 18,867,721 17,118,909 54,609,598
Montana Market Sales 4,962,337 7,039,039 9,053,839 9,053,839 9,004,303
Montana Contract Sales 4,127,712 2,112,912 98,112 98,112 98,112
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 65,774,586 65,193,206 63,846,150 62,810,776 63,712,014
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 468,582 473,290 471,361 472,629 1,062,356
Merchant Energy Sales 759,917 732,512 679,366 633,673 2,184,224
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) 1,422,137 1,476,390 1,588,850 1,696,265 (5,983)
Montana Merchant Revenues 216,328 313,333 412,860 429,258 444,216
Montana Contract Revenues 155,517 74,353 (6,855) (7,425) (4,804)
Trading -- -- -- -- --
Other 21,275 21,302 20,328 19,055 6,000
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,043,756 3,091,180 3,165,910 3,243,455 3,686,010
- --------------------------------------------------------------------------------------------------------------------
A-111
PPL Consolidation
High Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 502,569 597,965 642,892 646,570 844,820
O&M 401,414 432,341 470,464 482,429 530,084
Other Montana Operating Expenses 21,581 22,123 22,667 23,193 23,774
Nuclear Decommissioning Expense 23,666 21,969 20,696 19,422 18,149
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 949,230 1,074,398 1,156,719 1,171,614 1,416,827
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 47,435 40,986 38,880 36,727 35,240
Operating Cash Flow ($000) 1,170,521 1,649,792 1,326,068 1,411,666 1,442,464
Capital Expenditures ($000)
Pennsylvania Fossil 106,197 98,067 86,395 95,153 94,225
Pennsylvania Hydro 4,826 959 937 1,407 3,677
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 37,710 49,500 67,500 48,600 35,100
Pennsylvania Nuclear Fuel 55,803 55,306 54,788 56,158 57,562
Other New Projects 53,496 -- -- -- --
Montana 23,472 50,409 48,248 48,457 56,970
Maine 3,878 4,503 9,080 5,965 1,140
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 285,381 258,744 266,949 255,740 248,675
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 36,127 48,338 46,110 42,744 37,490
Lease Payments for Lower Mt Bethel ($000) -- -- -- 35,822 35,464
Lease Payments for New Peakers ($000) -- 26,488 76,669 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 849,013 1,316,222 936,340 986,161 1,029,636
====================================================================================================================
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 876,863 887,101 899,808 913,551 866,313
O&M 540,587 562,572 609,714 596,205 616,666
Other Montana Operating Expenses 24,356 24,953 25,563 26,163 26,803
Nuclear Decommissioning Expense 16,875 15,602 14,328 13,055 --
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,458,680 1,490,228 1,549,413 1,548,974 1,509,782
- ---------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 34,259 33,118 31,938 31,192 31,427
Operating Cash Flow ($000) 1,550,816 1,567,835 1,584,559 1,663,289 2,144,801
Capital Expenditures ($000)
Pennsylvania Fossil 59,410 60,042 105,478 150,621 106,142
Pennsylvania Hydro 1,102 1,123 1,145 1,167 1,190
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 18,329 18,787 19,257 19,738 20,232
Pennsylvania Nuclear Fuel 59,001 60,476 61,988 63,538 65,126
Other New Projects -- -- -- -- --
Montana 19,048 13,663 13,456 13,710 14,085
Maine 1,250 1,256 1,263 1,269 1,276
- ---------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 158,140 155,347 202,586 250,043 208,051
- ---------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 37,283 35,219 37,209 38,847 40,501
Lease Payments for Lower Mt Bethel ($000) 35,109 34,758 34,411 34,066 33,726
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
=====================================================================================================================
Cash from Domestic Generation Assets 1,229,086 1,251,312 1,219,155 1,249,134 1,771,325
=====================================================================================================================
A-112
PPL Consolidation
High Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 44,762 46,412 47,537 48,725 49,944
PPL Energy Plus 28,032 29,127 27,867 28,564 29,278
IEC (Interstate Energy Co.) 33 34 35 36 37
PPL Global 2,424 2,553 2,660 2,727 2,795
PPL Services 36,443 37,410 38,313 39,271 40,253
Indirect Costs 61,870 70,918 75,881 77,778 79,722
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (17,767) (18,408) (18,979) (17,992) (18,442)
=====================================================================================================================
Non-Operating and G&A Expenses 155,797 168,046 173,314 179,108 183,586
=====================================================================================================================
=====================================================================================================================
Total Cash Available {1}, {2} 673,727 1,173,653 832,437 881,645 926,209
=====================================================================================================================
Interest Expense 126,828 60,361 62,304 64,029 63,996
Debt Service Coverage Ratio 5.31 19.44 13.36 13.77 14.47
-----------------------------------
Average 2001 - 2010 16.66
Minimum 2001 - 2010 5.31
Average 2001 - 2005 13.27
Average 2006 - 2010 17.84
-----------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 51,192 52,472 53,784 55,128 56,507
PPL Energy Plus 30,010 30,760 31,529 32,317 33,125
IEC (Interstate Energy Co.) 38 39 40 41 42
PPL Global 2,865 2,936 3,010 3,085 3,162
PPL Services 41,259 42,290 43,348 44,431 45,542
Indirect Costs 81,716 83,758 85,852 87,999 90,199
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (18,903) (19,376) (19,860) (20,356) (20,865)
===================================================================================================================
Non-Operating and G&A Expenses 188,176 192,880 197,702 202,644 207,711
===================================================================================================================
===================================================================================================================
Total Cash Available {1}, {2} 1,155,494 1,188,158 1,164,306 1,203,003 1,726,563
===================================================================================================================
Interest Expense 64,769 64,525 63,978 64,009 64,009
Debt Service Coverage Ratio 17.84 18.41 18.20 18.79 26.97
-----------------------------------
Average 2001 - 2010 16.66
Minimum 2001 - 2010 5.31
Average 2001 - 2005 13.27
Average 2006 - 2010 17.84
-----------------------------------
{1} Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
{2} The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-113
PPL Consolidation
High Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,616,571 26,551 836 26,489,649 26,429,912 26,372,527
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 2,878,262 2,958,112 3,040,315 3,124,948 3,212,091
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 7,840,278 8,129,393 8,441,552 8,779,288 9,145,725
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 250,987 250,987 250,987 250,987 250,987
NUG Contracts 40,364 40,364 40,364 39,258 --
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 63,712,723 64,016,952 64,349,129 64,710,654 65,067,591
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 54,709,380 55,013,609 55,345,785 55,707,310 56,064,248
Montana Market Sales 8,905,231 8,905,231 8,905,231 8,905,231 8,962,463
Montana Contract Sales 98,112 98,112 98,112 98,112 40,880
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 63,712,723 64,016,952 64,349,129 64,710,654 65,067,591
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 1,077,377 1,093,268 1,109,449 1,125,914 1,142,215
Merchant Energy Sales 2,259,158 2,336,377 2,417,053 2,501,387 2,588,032
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) (2,421) (2,421) (2,421) (2,355) --
Montana Merchant Revenues 449,174 459,570 470,214 481,112 494,950
Montana Contract Revenues 2,034 2,076 2,119 2,164 921
Trading -- -- -- -- --
Other 6,000 6,000 6,000 6,000 3,000
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,791,322 3,894,870 4,002,415 4,114,222 4,229,118
- --------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,416,896 26,461,668 26,506,846 26,552,434 26,598,437
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 3,147,092 3,083,580 3,021,515 2,960,862 2,901,584
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 9,115,175 9,088,764 9,066,150 9,047,029 9,031,136
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 250,987 250,987 250,987 250,987 250,987
NUG Contracts -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 65,016,411 64,971,260 64,931,759 64,897,574 64,868,405
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 56,013,068 55,967,916 55,928,416 55,894,231 55,865,062
Montana Market Sales 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Contract Sales -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 65,016,411 64,971,260 64,931,759 64,897,574 64,868,405
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 1,164,970 1,188,363 1,212,421 1,237,169 1,203,285
Merchant Energy Sales 2,631,153 2,675,428 2,720,869 2,767,491 2,815,312
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) -- -- -- -- --
Montana Merchant Revenues 505,680 514,900 524,545 534,636 545,197
Montana Contract Revenues -- -- -- -- --
Trading -- -- -- -- --
Other -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 4,301,803 4,378,691 4,457,835 4,539,296 4,563,794
- --------------------------------------------------------------------------------------------------------------------
A-114
PPL Consolidation
High Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 890,056 913,890 938,904 965,373 993,242
O&M 617,971 733,476 712,057 682,683 688,092
Other Montana Operating Expenses 27,456 28,125 28,812 29,512 30,226
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,535,484 1,675,491 1,679,773 1,677,567 1,711,559
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 32,179 22,178 22,744 23,285 23,214
Operating Cash Flow ($000) 2,223,659 2,197,201 2,299,898 2,413,370 2,494,344
Capital Expenditures ($000)
Pennsylvania Fossil 49,987 51,237 52,517 53,830 55,176
Pennsylvania Hydro 1,219 1,250 1,281 1,313 1,346
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 20,737 21,256 21,787 22,332 22,890
Pennsylvania Nuclear Fuel 66,754 68,423 70,134 71,887 73,684
Other New Projects -- -- -- -- --
Montana 14,463 19,351 18,112 18,565 21,202
Maine 1,308 1,341 1,374 1,408 1,444
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 154,468 162,857 165,205 169,336 175,742
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 40,922 41,406 44,330 45,820 39,783
Lease Payments for Lower Mt Bethel ($000) 33,389 33,055 32,724 32,397 32,073
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 1,903,682 1,868,685 1,966,440 2,074,619 2,155,548
====================================================================================================================
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 996,496 1,000,220 1,004,411 1,009,057 1,014,152
O&M 727,001 751,024 780,782 880,994 813,889
Other Montana Operating Expenses 30,956 31 704 32,476 33,264 34,096
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,754,452 1,782,949 1,817,669 1,923,315 1,862,137
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 23,123 23,701 24,293 24,899 25,522
Operating Cash Flow ($000) 2,524,228 2,572,042 2,615,873 2,591,082 2,676,135
Capital Expenditures ($000)
Pennsylvania Fossil 56,556 57,969 59,419 60,904 62,427
Pennsylvania Hydro 1,380 1,414 1,449 1,486 1,523
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 23,462 24,049 24,650 25,266 25,898
Pennsylvania Nuclear Fuel 75,526 77,415 79,350 81,334 83,367
Other New Projects -- -- -- -- --
Montana 19,505 19,993 20,492 21,004 21,529
Maine 1,480 1,517 1,555 1,593 1,633
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 177,909 182,357 186,915 191,588 196,377
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 15,292 3,935 3,668 3,401 3,134
Lease Payments for Lower Mt Bethel ($000) 31,752 31,435 31,120 30,809 30,501
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 2,208,077 2,263,117 2,302,971 2,274,086 2,354,925
====================================================================================================================
A-115
PPL Consolidation
High Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 57,919 59,367 60,851 62,373 63,932
PPL Energy Plus 33,953 34,802 35,672 36,564 37,478
IEC (Interstate Energy Co.) 43 44 45 46 47
PPL Global 3,241 3,322 3,405 3,490 3,577
PPL Services 46,681 47,848 49,044 50,270 51,527
Indirect Costs 92,454 94,765 97,134 99,562 102,052
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (21,387) (21,922) (22,470) (23,031) (23,607)
=====================================================================================================================
Non-Operating and G&A Expenses 212,903 218,226 223,682 229,274 235,005
=====================================================================================================================
=====================================================================================================================
Total Cash Available {1}, {2} 1,867,132 1,831,221 1,928,040 2,035,259 2,115,204
=====================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 29.17 28.61 30.12 31.80 33.05
--------------------------------
Average 2001 - 2010 16.66
Minimum 2001 - 2010 5.31
Average 2001 - 2005 13.27
Average 2006 - 2010 17.84
--------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 65,530 67,169 68,848 70,569 72,333
PPL Energy Plus 38,415 39,375 40,360 41,369 42,403
IEC (Interstate Energy Co.) 48 49 51 52 53
PPL Global 3,667 3,759 3,852 3,949 4,048
PPL Services 52,815 54,135 55,489 56,876 58,298
Indirect Costs 104,603 107,218 109,898 112,646 115,462
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (24,197) (24,802) (25,422) (26,058) (26,709)
====================================================================================================================
Non-Operating and G&A Expenses 240,881 246,903 253,075 259,402 265,887
====================================================================================================================
====================================================================================================================
Total Cash Available {1}, {2} 2,166,724 2,220,731 2,259,525 2,229,554 2,309,279
====================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 33.85 34.69 35.30 34.83 36.08
--------------------------------
Average 2001 - 2010 16.66
Minimum 2001 - 2010 5.31
Average 2001 - 2005 13.27
Average 2006 - 2010 17.84
--------------------------------
{1} Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
{2} The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-116
Exhibit II Independent Technical Review
Financial Projections -- Sensitivity Cases PPL Energy Supply LLC
- --------------------------------------------------------------------------------
Low Case Consolidated Cash Flow Summary
A-117
PPL Consolidation
Low Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects -- 630 630 1 232 1 232
Pennsylvania Nuclear 1,975 1,988 2,023 2,068 2,083
Other New Projects 248 1,215 1,755 1,755 2,955
Montana Fossil and Hydro 1,208 1,208 1,208 1,221 1,273
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 9,038 10,649 11,223 11,883 13,150
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,773,869 26,806,191 26,028,993 26,248,973 26,815,774
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects -- -- 530,264 3,590,756 3,947,780
Pennsylvania Nuclear 15,276,535 15,376,339 15,631,391 15,964,068 16,074,961
Other New Projects 1,106,914 2,551,267 3,947,120 3,489,881 12,938,019
Montana Fossil and Hydro 7,422,967 8,332,838 8,332,838 8,414,353 8,728,767
Montana Purchases - Basin 364,090 148,608 148,608 148,608 148,608
Maine 292,756 250,987 250,987 250,987 250,987
NUG Contracts 2,537,187 2,537,187 2,537,187 2,537,187 2,537,187
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 54,782,276 57,011,374 58,415,346 61,652,771 72,450,040
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 31,043,565 30,375,744 31,110,038 32,206,476 33,677,785
Other Contract Sales 3,485,801 3,303,729 3,283,033 1,156,654 --
Net Market Sales (Purchases) 10,263,631 12,701,171 13,340,848 17,470,110 27,537,435
Montana Market Sales 2,573,057 3,964,990 4,353,734 4,435,249 4,749,663
Montana Contract Sales 5,214,000 4,516,456 4,127,712 4,127,712 4,127,712
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 52,580,054 54,862,091 56,215,365 59,396,201 70,092,595
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 280,955 117,620 299,947 333,028 456,594
Merchant Energy Sales 258,264 313,098 337,937 440,337 692,094
Contract Capacity Sales (Purchases) 54,000 63,000 66,600 30,900 --
Contract Energy Sales (Purchases) 1,131,869 1,201,237 1,157,977 1,185,828 1,266,291
Montana Merchant Revenues 130,561 85,694 97,469 88,162 104,147
Montana Contract Revenues 101,985 129,838 156,748 156,336 155,882
Trading -- -- -- -- --
Other 26,565 25,169 23,896 22,622 21,949
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,984,199 1,935,657 2,140,574 2,257,213 2,696,957
- --------------------------------------------------------------------------------------------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1 232 1 232 1 232 1 232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,307 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,184 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 26,595,835 26,390,276 26,198,099 26,018,398 25,850,354
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 4,059,466 4,174,578 4,293,231 4,415,547 4,541,651
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 12,998,871 13,080,855 13,184,305 13,309,962 13,458,972
Montana Fossil and Hydro 8,941,441 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin 148,608 148,608 148,608 148,608 99,072
Maine 250,987 250,987 250,987 250,987 287,691
NUG Contracts 2,537,187 2,537,187 1,772,806 1,268,608 95,335
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 72,615,313 72,668,752 71,934,297 71,498,371 70,419,337
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales 34,404,881 35,125,621 35,826,477 36,539,915 --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 26,712,041 25,932,386 24,448,015 23,248,710 61,316,922
Montana Market Sales 4,962,337 7,039,039 9,053,839 9,053,839 9,004,303
Montana Contract Sales 4,127,712 2,112,912 98,112 98,112 98,112
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 70,206,972 70,209,958 69,426,444 68,940,577 70,419,337
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 449,595 442,764 430,012 419,437 874,542
Merchant Energy Sales 681,777 671,783 641,908 617,994 1,800,193
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) 1,422,137 1,476,390 1,588,850 1,696,265 (5,983)
Montana Merchant Revenues 108,144 175,651 243,025 243,825 242,629
Montana Contract Revenues 155,517 74,353 (6,855) (7,425) (4,804)
Trading -- -- -- -- --
Other 21,275 21,302 20,328 19,055 6,000
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,838,445 2,862,243 2,917,269 2,989,151 2,912,578
- --------------------------------------------------------------------------------------------------------------------
A-118
PPL Consolidation
Low Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 490,337 569,428 593,067 625,842 805,593
O&M 401,589 432,159 470,354 483,314 531,060
Other Montana Operating Expenses 21,581 22,123 22,667 23,193 23,774
Nuclear Decommissioning Expense 23,666 21,969 20,696 19,422 18,149
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 937,173 1,045,678 1,106,784 1,151,771 1,378,575
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 47,435 40,986 38,880 36,727 35,240
Operating Cash Flow ($000) 999,590 848,992 994,910 1,068,715 1,283,141
Capital Expenditures ($000)
Pennsylvania Fossil 106,197 98,067 86,395 95,153 94,225
Pennsylvania Hydro 4,826 959 937 1,407 3,677
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 37,710 49,500 67,500 48,600 35,100
Pennsylvania Nuclear Fuel 55,803 55,306 54,788 56,158 57,562
Other New Projects 53,496 -- -- -- --
Montana 23,472 50,409 48,248 48,457 56,970
Maine 3,878 4,503 9,080 5,965 1,140
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 285,381 258,744 266,949 255,740 248,675
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 36,127 48,338 46,110 42,744 37,490
Lease Payments for Lower Mt Bethel ($000) -- -- -- 35,822 35,464
Lease Payments for New Peakers ($000) -- 26,488 76,669 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 678,082 515,422 605,182 643,211 870,314
====================================================================================================================
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 845,598 859,544 875,332 891,601 847,666
O&M 541,980 564,374 611,927 598,841 619,745
Other Montana Operating Expenses 24,356 24,953 25,563 26,163 26,803
Nuclear Decommissioning Expense 16,875 15,602 14,328 13,055 --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,428,810 1,464,473 1,527,150 1,529,660 1,494,214
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 34,259 33,118 31,938 31,192 31,427
Operating Cash Flow ($000) 1,375,376 1,364,652 1,358,180 1,428,299 1,386,937
Capital Expenditures ($000)
Pennsylvania Fossil 59,410 60,042 105,478 150,621 106,142
Pennsylvania Hydro 1,102 1,123 1,145 1,167 1,190
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 18,329 18,787 19,257 19,738 20,232
Pennsylvania Nuclear Fuel 59,001 60,476 61,988 63,538 65,126
Other New Projects -- -- -- -- --
Montana 19,048 13,663 13,456 13,710 14,085
Maine 1,250 1,256 1,263 1,269 1,276
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 158,140 155,347 202,586 250,043 208,051
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 37,283 35,219 37,209 38,847 40,501
Lease Payments for Lower Mt Bethel ($000) 35,109 34,758 34,411 34,066 33,726
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 1,053,646 1,048,129 992,776 1,014,144 1,013,461
====================================================================================================================
A-119
PPL Consolidation
Low Case
Cash Flow Summary
2001 2002 2003 2004 2005
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 44,762 46,412 47,537 48,725 49,944
PPL Energy Plus 28,032 29,127 27,867 28,564 29,278
IEC (Interstate Energy Co.) 33 34 35 36 37
PPL Global 2,424 2,553 2,660 2,727 2,795
PPL Services 36,443 37,410 38,313 39,271 40,253
Indirect Costs 61,870 70,918 75,881 77,778 79,722
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (17,767) (18,408) (18,979) (17,992) (18,442)
=====================================================================================================================
Non-Operating and G&A Expenses 155,797 168,046 173,314 179,108 183,586
=====================================================================================================================
=====================================================================================================================
Total Cash Available {1}, {2} 502,796 372,852 501,279 538,695 766,887
=====================================================================================================================
Interest Expense 126,828 60,361 62,304 64,029 63,996
Debt Service Coverage Ratio 3.96 6.18 8.05 8.41 11.98
---------------------------------
Average 2001 - 2010 11.39
Minimum 2001 - 2010 3.96
Average 2001 - 2005 7.72
Average 2006 - 2010 14.66
---------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 51,192 52,472 53,784 55,128 56,507
PPL Energy Plus 30,010 30,760 31,529 32,317 33,125
IEC (Interstate Energy Co.) 38 39 40 41 42
PPL Global 2,865 2,936 3,010 3,085 3,162
PPL Services 41,259 42,290 43,348 44,431 45,542
Indirect Costs 81,716 83,758 85,852 87,999 90,199
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (18,903) (19,376) (19,860) (20,356) (20,865)
====================================================================================================================
Non-Operating and G&A Expenses 188,176 192,880 197,702 202,644 207,711
====================================================================================================================
====================================================================================================================
Total Cash Available {1}, {2} 980,054 984,975 937,928 968,013 968,699
====================================================================================================================
Interest Expense 64,769 64,525 63,978 64,009 64,009
Debt Service Coverage Ratio 15.13 15.26 14.66 15.12 15.13
---------------------------------
Average 2001 - 2010 11.39
Minimum 2001 - 2010 3.96
Average 2001 - 2005 7.72
Average 2006 - 2010 14.66
---------------------------------
{1} Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
{2} The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-120
PPL Consolidation
Low Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 25,491,534 25,159,163 24,851,022 24,565,101 24,299,581
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 4,490,086 4,440,841 4,393,787 4,348,800 4,305,763
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 13,039,609 12,663,069 12,331,155 12,046,562 11,813,075
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 287,691 287,691 287,691 287,691 287,691
NUG Contracts 40,364 40,364 40,364 39,258 --
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 69,435,546 68,677,391 67,990,282 67,373,674 66,792,372
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 60,432,203 59,674,047 58,986,938 58,370,331 57,789,029
Montana Market Sales 8,905,231 8,905,231 8,905,231 8,905,231 8,962,463
Montana Contract Sales 98,112 98,112 98,112 98,112 40,880
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 69,435,546 68,677,391 67,990,282 67,373,674 66,792,372
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 862,673 851,604 840,868 830,450 821,686
Merchant Energy Sales 1,834,656 1,873,282 1,914,657 1,958,930 2,005,070
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) (2,421) (2,421) (2,421) (2,355) --
Montana Merchant Revenues 241,833 245,138 248,500 251,921 257,259
Montana Contract Revenues 2,034 2,076 2,119 2,164 921
Trading -- -- -- -- --
Other 6,000 6,000 6,000 6,000 3,000
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,944,775 2,975,679 3,009,724 3,047,110 3,087,935
- --------------------------------------------------------------------------------------------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Net Capacity (MW)
Pennsylvania Fossil 5,227 5,227 5,227 5,227 5,227
Pennsylvania Hydro 285 285 285 285 285
Pennsylvania New Projects 1,232 1,232 1,232 1,232 1,232
Pennsylvania Nuclear 2,083 2,083 2,083 2,083 2,083
Other New Projects 2,955 2,955 2,955 2,955 2,955
Montana Fossil and Hydro 1,317 1,317 1,317 1,317 1,317
Maine 95 95 95 95 95
- --------------------------------------------------------------------------------------------------------------------
Total Net Capacity 13,195 13,195 13,195 13,195 13,195
- --------------------------------------------------------------------------------------------------------------------
Net Generation (MWh)
Pennsylvania Fossil 24,352,134 24,406,006 24,461,214 24,517,775 24,575,707
Pennsylvania Hydro 1,007,958 1,007,958 1,007,958 1,007,958 1,007,958
Pennsylvania New Projects 4,045,990 3,806,371 3,585,025 3,380,300 3,190,737
Pennsylvania Nuclear 16,074,961 16,074,961 16,074,961 16,074,961 16,074,961
Other New Projects 11,725,880 11,652,980 11,593,770 11,547,798 11,514,755
Montana Fossil and Hydro 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Purchases - Basin -- -- -- -- --
Maine 286,025 284,435 282,916 281,467 280,083
NUG Contracts -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Net Generation 66,496,291 66,236,053 66,009,187 65,813,603 65,647,545
- --------------------------------------------------------------------------------------------------------------------
Power Sales (MWh)
PLR (Provider of Last Resort) Sales -- -- -- -- --
Other Contract Sales -- -- -- -- --
Net Market Sales (Purchases) 57,492,947 57,232,710 57,005,844 56,810,259 56,644,201
Montana Market Sales 9,003,343 9,003,343 9,003,343 9,003,343 9,003,343
Montana Contract Sales -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Power Sales 66,496,291 66,236,053 66,009,187 65,813,603 65,647,545
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues ($000)
Merchant Capacity Sales 834,542 847,767 861 370 875,359 847,667
Merchant Energy Sales 2,026,638 2,049,452 2,073,514 2,098,829 2,125,407
Contract Capacity Sales (Purchases) -- -- -- -- --
Contract Energy Sales (Purchases) -- -- -- -- --
Montana Merchant Revenues 264,863 271,534 278,619 286,142 294,125
Montana Contract Revenues -- -- -- -- --
Trading -- -- -- -- --
Other -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,126,043 3,168,753 3,213,504 3,260,330 3,267,199
- --------------------------------------------------------------------------------------------------------------------
A-121
PPL Consolidation
Low Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 846,346 845,878 846,038 847,073 848,758
O&M 621,133 736,744 715,460 686,256 691,878
Other Montana Operating Expenses 27,456 28,125 28,812 29,512 30,226
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,494,935 1,610,747 1,590,310 1,562,840 1,570,862
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 32,179 22,178 22,744 23,285 23,214
Operating Cash Flow ($000) 1,417,661 1,342,754 1,396,670 1,460,984 1,493,859
Capital Expenditures ($000)
Pennsylvania Fossil 49,987 51,237 52,517 53,830 55,176
Pennsylvania Hydro 1,219 1,250 1,281 1,313 1,346
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 20,737 21,256 21,787 22,332 22,890
Pennsylvania Nuclear Fuel 66,754 68,423 70,134 71,887 73,684
Other New Projects -- -- -- --
Montana 14,463 19,351 18,112 18,565 21,202
Maine 1,308 1,341 1,374 1,408 1,444
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 154,468 162,857 165,205 169,336 175,742
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 40,922 41,406 44,330 45,820 39,783
Lease Payments for Lower Mt Bethel ($000) 33,389 33,055 32,724 32,397 32,073
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 1,097,684 1,014,237 1,063,212 1,122,233 1,155,062
====================================================================================================================
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Domestic Generation Assets
Operating Expenses ($000)
Fuel 849,962 852,053 855,012 858,823 863,478
O&M 730,839 754,938 784,794 885,128 818,173
Other Montana Operating Expenses 30,956 31,704 32,476 33,264 34,096
Nuclear Decommissioning Expense -- -- -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,611,757 1,638,695 1,672,282 1,777,216 1,715,746
- --------------------------------------------------------------------------------------------------------------------
Non-Income Taxes ($000) 23,123 23,701 24,293 24,899 25,522
Operating Cash Flow ($000) 1,491,162 1,506,357 1,516,928 1,458,216 1,525,931
Capital Expenditures ($000)
Pennsylvania Fossil 56,556 57,969 59,419 60,904 62,427
Pennsylvania Hydro 1,380 1,414 1,449 1,486 1,523
Pennsylvania New Projects -- -- -- -- --
Pennsylvania Nuclear Projects 23,462 24,049 24,650 25,266 25,898
Pennsylvania Nuclear Fuel 75,526 77,415 79,350 81,334 83,367
Other New Projects -- -- -- -- --
Montana 19,505 19,993 20,492 21,004 21,529
Maine 1,480 1,517 1,555 1,593 1,633
- --------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures 177,909 182,357 186,915 191,588 196,377
- --------------------------------------------------------------------------------------------------------------------
Montana Debt Service ($000) 15,292 3,935 3,668 3,401 3,134
Lease Payments for Lower Mt Bethel ($000) 31,752 31,435 31,120 30,809 30,501
Lease Payments for New Peakers ($000) 91,198 91,198 91,198 91,198 91,198
====================================================================================================================
Cash from Domestic Generation Assets 1,175,011 1,197,433 1,204,026 1,141,220 1,204,720
====================================================================================================================
A-122
PPL Consolidation
Low Case
Cash Flow Summary
2011 2012 2013 2014 2015
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 57,919 59,367 60,851 62,373 63,932
PPL Energy Plus 33,953 34,802 35,672 36,564 37,478
IEC (Interstate Energy Co.) 43 44 45 46 47
PPL Global 3,241 3,322 3,405 3,490 3,577
PPL Services 46,681 47,848 49,044 50,270 51,527
Indirect Costs 92,454 94,765 97,134 99,562 102,052
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (21,387) (21,922) (22,470) (23,031) (23,607)
=====================================================================================================================
Non-Operating and G&A Expenses 212,903 218,226 223,682 229,274 235,005
=====================================================================================================================
=====================================================================================================================
Total Cash Available {1}, {2} 1,061,134 976,774 1,024,812 1,082,873 1,114,719
=====================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 16.58 15.26 16.01 16.92 17.42
-------------------------------
Average 2001 - 2010 11.39
Minimum 2001 - 2010 3.96
Average 2001 - 2005 7.72
Average 2006 - 2010 14.66
-------------------------------
2016 2017 2018 2019 2020
---- ---- ---- ---- ----
PPL Overhead Expenses
Non-Operating and G&A Expenses ($000)
PPL Generation 65,530 67,169 68,848 70,569 72,333
PPL Energy Plus 38,415 39,375 40,360 41,369 42,403
IEC (Interstate Energy Co.) 48 49 51 52 53
PPL Global 3,667 3,759 3,852 3,949 4,048
PPL Services 52,815 54,135 55,489 56,876 58,298
Indirect Costs 104,603 107,218 109,898 112,646 115,462
Benefit Loading -- -- -- -- --
G&A Recovery from AEC (24,197) (24,802) (25,422) (26,058) (26,709)
====================================================================================================================
Non-Operating and G&A Expenses 240,881 246,903 253,075 259,402 265,887
====================================================================================================================
====================================================================================================================
Total Cash Available {1}, {2} 1,133,659 1,155,047 1,160,581 1,096,687 1,159,075
====================================================================================================================
Interest Expense 64,009 64,009 64,009 64,009 64,009
Debt Service Coverage Ratio 17.71 18.05 18.13 17.13 18.11
-------------------------------
Average 2001 - 2010 11.39
Minimum 2001 - 2010 3.96
Average 2001 - 2005 7.72
Average 2006 - 2010 14.66
-------------------------------
{1} Projected Total Revenue and Expense do not include certain operations of
PPL EnergyPlus marketing and trading organization and certain
unconsolidated international operations including investments in the
United Kingdom.
{2} The 2001 cash flow is not based on actual market prices or electricity
generation. Actual performance in 2001 may differ significantly from that
shown in the Financial Projections.
A-123
ANNEX B
[LOGO] ICF CONSULTING INDEPENDENT MARKETING
CONSULTANT'S REPORT
Market Assessment of the PPL
Corporation Generation Portfolio
and Associated U.S. Power
Markets
Prepared for:
PPL Corporation
Prepared by:
ICF Consulting
June 2001
B-1
- --------------------------------------------------------------------------------
IMPORTANT NOTICE TO THIRD PARTIES:
REVIEW OR USE OF THIS REPORT BY ANY PARTY OTHER THAN THE CLIENT CONSTITUTES
ACCEPTANCE OF THE FOLLOWING TERMS. Read these terms carefully. They constitute a
binding agreement between you and ICF Resources, Inc ("ICF"). By your review or
use of the report, you hereby agree to the following terms.
Any use of this report other than as a whole and in conjunction with this
disclaimer is forbidden.
This report may not be copied in whole or in part or distributed to anyone. This
report and information and statements herein are based in whole or in part on
information obtained from various sources. ICF makes no assurances as to the
accuracy of any such information or any conclusions based thereon. ICF bears no
responsibility for the results of any actions taken on the basis of this report.
The report is provided AS IS.
NO WARRANTY, WHETHER EXPRESS OR IMPLIED, INCLUDING THE IMPLIED WARRANTIES OF
MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE IS GIVEN OR MADE BY ICF IN
CONNECTION WITH THIS REPORT.
- --------------------------------------------------------------------------------
(C)2001 ICF Resources, Inc. All Rights Reserved
TABLE OF CONTENTS
- --------------------------------------------------------------------------------
Page
Executive Summary ......................................................... 1
Overview .................................................................. 1
Current U.S. Power Market Conditions ...................................... 2
Diversification and the PPL Portfolio ..................................... 3
Conclusions ............................................................... 6
The Modeling Approach ..................................................... 7
Elements of the Forecast .................................................. 8
Regional Wholesale Power Price Forecasts - Regional Summary ............... 15
Power Plant Dispatch ...................................................... 17
PPL Fleet Revenue Assessment .............................................. 22
Organization of Report .................................................... 25
CHAPTER ONE Historical Pricing and Market Structure in PJM, NEPOOL,
NY, MAIN, Montana, AZNM, and PacNW ........................................ 26
Introduction .............................................................. 26
Forecast versus Historical ................................................ 26
Cross-Regional Power Price Comparisons .................................... 28
Regional Price Discussion ................................................. 31
Market Structure .......................................................... 44
CHAPTER TWO The PJM Regional Wholesale Market ............................. 49
Introduction .............................................................. 49
PJM History and Background ................................................ 49
Transmission Within PJM ................................................... 50
Transmission With Neighboring Regions ..................................... 51
Capacity and Generation Mix ............................................... 53
Supply and Demand Balance ................................................. 53
PJM Evolving Market Structure ............................................. 55
CHAPTER THREE The WSCC Regional Wholesale Markets ......................... 58
Introduction .............................................................. 58
Market Structure - Participants ........................................... 59
Transmission Within WSCC .................................................. 60
Intra-Regional Transmission ............................................... 62
Capacity and Generation Mix ............................................... 64
- --------------------------------------------------------------------------------
i [LOGO] ICF CONSULTING
TABLE OF CONTENTS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Supply and Demand Balance ................................................. 67
Near-Term Hydro Conditions ................................................ 70
CHAPTER FOUR The NEPOOL Regional Wholesale Market ......................... 73
Introduction .............................................................. 73
Market Structure - Participants ........................................... 73
Transmission Within NEPOOL ................................................ 74
Transmission With Neighboring Regions ..................................... 75
Capacity and Generation Mix ............................................... 77
Supply and Demand Balance ................................................. 78
NEPOOL Market Structure ................................................... 81
CHAPTER FIVE Modeling Approach and Input Assumptions ...................... 83
Modeling .................................................................. 83
Methodology ............................................................... 83
Regional Assumptions ...................................................... 90
Summary of Assumptions .................................................... 92
Capacity .................................................................. 139
CHAPTER SIX PPL Unit Level Assumptions and Results ........................ 151
Introduction .............................................................. 151
Summary of Generation Assets by Region .................................... 152
Summary of Generation Assets by Asset Type ................................ 158
CHAPTER SEVEN Detailed Market Price and Fleet Operating Revenue Results ... 171
Regional Energy and Capacity Prices - Base Case ........................... 171
Summary of Results - High Fuel Case ....................................... 182
Summary of Results - Low Case ............................................. 186
Portfolio Revenue and Dispatch Assessment ................................. 188
- --------------------------------------------------------------------------------
ii [LOGO] ICF CONSULTING
LIST OF EXHIBITS
- --------------------------------------------------------------------------------
Page
Exhibit ES-1 U.S. Reserve Levels Have Been Falling ........................ 2
Exhibit ES-2 PJM Wholesale Electricity Prices (Nominal$/MWh) .............. 2
Exhibit ES-3 Location of PPL GenCo Assets ................................. 3
Exhibit ES-4 Historical Regional Summer On-Peak Pricing ................... 4
Exhibit ES-5 Summary of PPL Asset Characteristics by Region ............... 5
Exhibit ES-6 Summary of PPL Asset Characteristics by Capacity Type ........ 6
Exhibit ES-7 Summary of Key Modeling Assumptions - Base Case .............. 9
Exhibit ES-8 Natural Gas Prices - Henry Hub - Real Dollars (1998$/MMBtu) .. 14
Exhibit ES-9 Summary of ICF Firm Power Price Forecasts by Region and
Case - All Hours - Real Dollars ....................................... 15
Exhibit ES-10 Summary of ICF Base Case Firm Power Price Forecasts by
Region - Real ......................................................... 16
Exhibit ES-11 Summary of ICF Base Case Firm Power Price Forecasts by
Region - Nominal ...................................................... 17
Exhibit ES-12 Projected Capacity Factor of PPL Generating Stations by
Region and Capacity Type - Base Case 2005 ............................. 18
Exhibit ES-13 Base Case Illustrative Summer Peak Supply Curve
2005 - PJM ............................................................ 18
Exhibit ES-14 Base Case Illustrative Winter Peak Supply Curve
2005 - PJM ............................................................ 19
Exhibit ES-15 Base Case Illustrative Summer Peak Supply Curve
2005 - NEPOOL ......................................................... 20
Exhibit ES-16 Base Case Illustrative Winter Peak Supply Curve
2005 - NEPOOL ......................................................... 21
Exhibit ES-17 Base Case Illustrative Summer Peak Supply Curve
2005 - Montana ........................................................ 22
Exhibit ES-18 NPV of PPL Generating Stations by Region and Case ........... 23
Exhibit ES-19 NPV of PPL Generating Stations by Capacity Type and Case .... 24
Exhibit 1-1 Near-Term Base Case Firm Power Price Forecast versus
Historical (Real 1998$/MWh) ........................................... 27
Exhibit 1-2 Historical versus Forecast Prices - (Real 1998$/MWh) .......... 27
Exhibit 1-3 Forecast versus Annual Historical - All-Hours Firm
Prices - Real Dollars (1998$/MWh) ..................................... 28
Exhibit 1-4 Historical Regional Summer On-Peak Prices ..................... 28
Exhibit 1-5 1996 Real Wholesale Electric Energy Prices .................... 29
Exhibit 1-6 1998 On-Peak Power Markets Week Index of Regional Power
Prices ................................................................ 30
Exhibit 1-7 2000 On-Peak Power Markets Week Index of Regional Power
Prices ................................................................ 31
Exhibit 1-8 Comparison of Northeastern and California Markets ............. 32
Exhibit 1-9 PJM(1) Historical Prices - Nominal $/MWh ...................... 32
Exhibit 1-10 PJM Weekly Peak Indices - Power Markets Week ................. 33
Exhibit 1-11 PJM Locational Marginal Prices 1999-2000 ..................... 34
Exhibit 1-12 Capacity Trading at PJM - Daily Trading ...................... 35
Exhibit 1-13 PJM Power Prices vs. Fuel Costs .............................. 36
Exhibit 1-14 Historical NEPOOL Prices (Real $/MWh) ........................ 37
Exhibit 1-15 Historical NEPOOL Prices (Nominal $/MWh) ..................... 38
Exhibit 1-16 Historical NYPP Prices (Nominal $/MWh) ....................... 39
Exhibit 1-17 Historical NYPP Prices (Nominal $/MWh) ....................... 39
Exhibit 1-18 Original Membership in the Alliance ISO ...................... 42
Exhibit 1-19 Original Membership in the Midwest ISO ....................... 42
Exhibit 1-20 Historical On-Peak Prices Indices (Palo Verde/Four
Corners/COB/Mid Columbia) ............................................. 44
- --------------------------------------------------------------------------------
iii [LOGO] ICF CONSULTING
LIST OF EXHIBITS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Exhibit 1-21 Historical All-Hours Firm Power Prices (Nominal$/MWh) ........ 44
Exhibit 1-22 National Deregulation Status as of July 2000 ................. 46
Exhibit 2-1 Major Participants in PJM - ICF Defined Transmission Regions .. 50
Exhibit 2-2 PJM Intra-Regional Transmission ............................... 51
Exhibit 2-3 Eastern Interconnect Total Transfer Capability (GW) ........... 52
Exhibit 2-4 Total Regional Imports and Capability ......................... 52
Exhibit 2-5 PJM Capacity and Generation Mix - 1999 ........................ 53
Exhibit 2-6 Historical Peak Demand and Energy Growth Rates in PJM ......... 54
Exhibit 2-7 Forecast PJM Supply and Demand Balance, 2001 .................. 55
Exhibit 2-8 PJM Product Overlap ........................................... 55
Exhibit 3-1 WSCC Regional Division - ICF Defined Transmission Regions ..... 58
Exhibit 3-2 WSCC Historical Market Participants ........................... 59
Exhibit 3-3 WSCC Total Transfer Capability (GW) ........................... 61
Exhibit 3-4 Arizona/New Mexico Intra-Regional Transmission ................ 63
Exhibit 3-5 Montana and PacNW Intra-Regional Transmission ................. 64
Exhibit 3-6 Arizona/New Mexico Historical Regional Capacity and
Generation Mix - 1999 ................................................. 65
Exhibit 3-7 Montana Regional Capacity and Generation Mix - 1999 ........... 66
Exhibit 3-8 PacNW Regional Capacity and Generation Mix - 1999 ............. 66
Exhibit 3-9 Hydro Share of Total Generation by Region ..................... 67
Exhibit 3-10 Arizona/New Mexico Long-Term Annual Demand Growth Rates ...... 68
Exhibit 3-11 Arizona/New Mexico Historical Peak Demand and Energy
Growth Rates .......................................................... 68
Exhibit 3-12 NWPP Historical Peak Demand and Energy Growth ................ 69
Exhibit 3-13 Historical Demand Levels, Montana and PacNW versus NWPP ...... 69
Exhibit 3-14 Comparison of 2000 and 2001 Winter Conditions ................ 70
Exhibit 3-15 The Water Situation .......................................... 71
Exhibit 4-1 Major Historical Participants in NEPOOL ....................... 74
Exhibit 4-2 NEPOOL Intra-Regional Transmission ............................ 75
Exhibit 4-3 Eastern Interconnect Total Transfer Capability (GW) ........... 76
Exhibit 4-4 Historical Regional Capacity and Generation Mix - 1999 ........ 78
Exhibit 4-5 NEPOOL Historical Peak Demand and Energy Growth Rates ......... 80
Exhibit 4-6 NEPOOL Long-Term Annual Demand Growth Rates ................... 80
Exhibit 4-7 ............................................................... 81
Forecast NEPOOL Supply and Demand Balance, 2001 ........................... 81
Exhibit 4-8 NEPOOL Product Overlap ........................................ 82
Exhibit 5-1 Firm Power Prices Are the Sum of Energy and Capacity - An
Illustrative Example of a Smooth Transition to Equilibrium ............ 84
Exhibit 5-2 Three Examples of Firm Pricing ($/MWh) - Illustrative
All-Hours Prices ...................................................... 85
Exhibit 5-3 Power Prices - Commercial Topologies versus ICF Approach ...... 85
Exhibit 5-4 Illustrative Supply Curve for Electrical Energy ............... 87
Exhibit 5-5 Equilibrium in the Capacity Market ............................ 88
Exhibit 5-6 Seasonal Definition - Eastern Interconnect .................... 91
Exhibit 5-7 Seasonal Definition - WSCC .................................... 92
Exhibit 5-8 Summary of Key Modeling Assumptions - Base Case ............... 92
Exhibit 5-9 Historical Natural Gas Wellhead Prices (1940-1994) ............ 96
- --------------------------------------------------------------------------------
iv [LOGO] ICF CONSULTING
LIST OF EXHIBITS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Exhibit 5-10 Historical Henry Hub Prices (2000$) .......................... 97
Exhibit 5-11 Crude Oil Prices are the Highest Since 1990 WTI Cushing,
OK (Nominal$/BBl) ..................................................... 98
Exhibit 5-12 Long-Term Correlation Between Crude Oil Prices and Natural
Gas Prices 1980 - 1999 (1998$/MMBtu) .................................. 98
Exhibit 5-13 U.S. Natural Gas Rig Count ................................... 99
Exhibit 5-14 ICF Henry Hub Price Projections (Nominal$) ................... 99
Exhibit 5-15 NYMEX Futures versus ICF Gas Price Forecast .................. 101
Exhibit 5-16 ICF Base Case Forecast ($/MMBtu) ............................. 102
Exhibit 5-17 Natural Gas Outlook .......................................... 103
Exhibit 5-18 Henry Hub Historical and Forecast Prices - Real 1998$ ........ 104
Exhibit 5-19 Delivered Natural Gas Prices - Base Case ..................... 105
Exhibit 5-20 Delivered Natural Gas Prices - Downside Case ................. 106
Exhibit 5-21 Delivered Natural Gas Prices - High Case ..................... 107
Exhibit 5-22 Delivered Gas Price Seasonality - Eastern Interconnect ....... 108
Exhibit 5-23 Delivered Gas Price Seasonality - WSCC ....................... 108
Exhibit 5-24 Commodity Oil Prices Forecasts (1998$/Bbl) ................... 109
Exhibit 5-25 Delivered 1 Percent Residual Oil Prices by Region and
Case (1998$/Bbl) ...................................................... 109
Exhibit 5-26 Delivered Distillate Prices by Region and Case (1998$/Bbl) ... 109
Exhibit 5-27 U.S. Coal Supply Regions ..................................... 110
Exhibit 5-28 50-Year Historical Average Coal Prices ....................... 111
Exhibit 5-29 Coal Mine Labor Productivity Improvement Over Time ........... 112
Exhibit 5-30 Historical Central Appalachian Coal Price .................... 112
Exhibit 5-31 Minemouth Coal Prices at Representative Plants ............... 113
Exhibit 5-32 Total Annual Phase II SO(2) Allowances for the PPL GenCo
Fossil Units (tons of SO(2)) .......................................... 116
Exhibit 5-33 Historical SO(2) Allowance Prices (Nominal $) ................ 117
Exhibit 5-34 Historical NO(X) Allowance Prices (Nominal $) ................ 121
Exhibit 5-35 Post-Combustion NO(x) Controls for Coal Plants (1998$) ....... 122
Exhibit 5-36 ICF Gas Reburn Technology Characteristics (1998$) ............ 122
Exhibit 5-37 NO(x) Allowance Allocations to PPL GenCo ..................... 123
Exhibit 5-38 PJM Electricity Demand Assumptions ........................... 125
Exhibit 5-39 NEPOOL Electricity Demand Assumptions ........................ 125
Exhibit 5-40 Montana Electricity Demand Assumptions ....................... 126
Exhibit 5-41 AZNM Electricity Demand Assumptions .......................... 126
Exhibit 5-42 PacNW Electricity Demand Assumptions ......................... 126
Exhibit 5-43 Forecast Reserve Margin by Region- All Cases ................. 127
Exhibit 5-44 New Power Plant Characteristics .............................. 129
Exhibit 5-45 New Power Plant Capital Costs at ISO Conditions
(1998$/kW) - Base Case ................................................ 129
Exhibit 5-46 Regional Capital Cost Multipliers for Fossil-Fuel Units ...... 130
Exhibit 5-47 Eastern Interconnect New Unit Characteristics by Vintage -
Base and High Cases (1998$/kW) ........................................ 130
Exhibit 5-48 Eastern Interconnect New Unit Characteristics by Vintage -
Low Case (1998$/kW) ................................................... 131
- --------------------------------------------------------------------------------
v [LOGO] ICF CONSULTING
LIST OF EXHIBITS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Exhibit 5-49 WSCC New Unit Characteristics by Vintage - Base and
High Cases (1998$/kW) ................................................. 131
Exhibit 5-50 New Unit Characteristics by Vintage - Low Case (1998$/kW) .... 131
Exhibit 5-51 Unplanned Build Restrictions - All Cases ..................... 132
Exhibit 5-52 Calculation of the Annual Real Fixed Charge Rate for
Peaking Units (ARFCR) ................................................. 133
Exhibit 5-53 Calculation of the Annual Real Fixed Charge Rate
for Baseload Units (ARFCR) ............................................ 134
Exhibit 5-54 Firm Capacity Additions in PJM as of April 2001 .............. 135
Exhibit 5-55 Firm Capacity Additions in NEPOOL as of April 2001 ........... 136
Exhibit 5-56 AZNM Firm Capacity Additions as of April 2001 ................ 137
Exhibit 5-57 PacNW Firm Capacity Additions as of April 2001 ............... 138
Exhibit 5-58 LILCO Firm Capacity Additions as of April 2001 ............... 138
Exhibit 5-59 ComEd Firm Capacity Additions as of April 2001 ............... 139
Exhibit 5-60 PJM and NEPOOL Nuclear Unit Retirement Plans ................. 140
Exhibit 5-61 Nuclear Capacity Factor Projections (%) ...................... 141
Exhibit 5-62 Existing Unit Variable O&M and Turndown Assumptions .......... 142
Exhibit 5-63 Existing NUG Capacity - NEPOOL, LILCO, AZNM, PACNW, Montana .. 142
Exhibit 5-64 Existing NUG Capacity - PJM .................................. 143
Exhibit 5-65 Interconnected Grids in the U.S. and Canada .................. 144
Exhibit 5-66 Eastern Interconnect Transmission Capabilities ............... 145
Exhibit 5-67 WSCC Inter-Regional Total Transfer Capability (MW) ........... 146
Exhibit 5-68 Transmission Charges Across Areas and ISOs in the Eastern
Interconnect - ICF Estimate ........................................... 147
Exhibit 5-69 Transmission Charges Across Areas and ISOs in the
WSCC - ICF Estimate ................................................... 148
Exhibit 5-70 Transmission Charges Across ISOs - ICF Estimate .............. 148
Exhibit 5-71 Envisioned ISO Regions - ICF View of U.S. Eastern Interconnect 149
Exhibit 6-1 PPL Generating Stations Regional Diversification .............. 151
Exhibit 6-2 Summary of PPL Asset Characteristics by Region ................ 152
Exhibit 6-3 PPL PJM Generating Stations ................................... 153
Exhibit 6-4 Summary of PPL Asset Characteristics within PJM ............... 154
Exhibit 6-5 PPL NEPOOL Generating Stations ................................ 155
Exhibit 6-6 Summary of PPL Asset Characteristics within NEPOOL ............ 156
Exhibit 6-7 PPL Montana, Arizona, and PacNW Generating Stations ........... 156
Exhibit 6-8 Summary of PPL Asset Characteristics within Arizona, Montana,
and the Pacific Northwest ............................................. 157
Exhibit 6-9 Summary of PPL Asset Characteristics of Units Under
Development in LILCO and MAIN ......................................... 158
Exhibit 6-10 Summary of PPL Asset Characteristics by Unit Type ............ 158
Exhibit 6-11 Summary Capacity Block Characteristics - PPL PJM Coal Plants . 159
Exhibit 6-11 (continued) Summary Capacity Block Characteristics -
PPL PJM Coal Plants ................................................... 160
Exhibit 6-12 Summary Capacity Block Characteristics - PPL Montana
Coal Plants ........................................................... 160
Exhibit 6-13 Historical Capacity Factor at PPL Coal Units ................. 161
Exhibit 6-14 Historical Fuel Prices at Major PPL Coal Stations (1998$) .... 161
Exhibit 6-15 Projected Coal Costs (1998$) ................................. 162
Exhibit 6-16 Coal Unit Environmental Compliance ........................... 163
- --------------------------------------------------------------------------------
vi [LOGO] ICF CONSULTING
LIST OF EXHIBITS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Exhibit 6-17 PPL Hydro Plant Characteristics .............................. 164
Exhibit 6-18 Annual Hydro Capacity Factors (%) ............................ 165
Exhibit 6-19 Projected Monthly Hydro Plant Availability ................... 166
Exhibit 6-20 PPL Nuclear Plant Characteristics ............................ 166
Exhibit 6-21 PPL Oil/Gas Steam Plant Characteristics ...................... 167
Exhibit 6-22 PPL Combined Cycle Plant Characteristics ..................... 168
Exhibit 6-23 PPL Peaking and Mid-Level Plant Characteristics .............. 169
Exhibit 6-23 (continued) PPL LM6000 Plant Characteristics ................. 170
Exhibit 7-1 Base Case Western PJM Power Price Summary-Real 1998$ .......... 172
Exhibit 7-2 Base Case Western PJM Power Price Summary-Nominal Dollars ..... 173
Exhibit 7-3 Base Case NEPOOL Power Price Summary-Real 1998$ ............... 174
Exhibit 7-4 Base Case NEPOOL Power Price Summary-Nominal Dollars .......... 174
Exhibit 7-5 Base Case Montana Power Price Summary - Real 1998$ ............ 175
Exhibit 7-6 Base Case Montana Power Price Summary - Nominal Dollars ....... 176
Exhibit 7-7 Base Case AZNM Power Price Summary - Real 1998$ ............... 177
Exhibit 7-8 Base Case AZNM Power Price Summary - Nominal Dollars .......... 177
Exhibit 7-9 Base Case Pacific Northwest Power Price Summary - Real 1998$ .. 178
Exhibit 7-10 Base Case Pacific Northwest Power Price Summary - Nominal
Dollars ............................................................... 179
Exhibit 7-11 Base Case LILCO Power Price Summary - Real 1998$ ............. 180
Exhibit 7-12 Base Case LILCO Power Price Summary - Nominal Dollars ........ 180
Exhibit 7-13 Base Case ComEd Power Price Summary - Real 1998$ ............. 181
Exhibit 7-14 Base Case ComEd Power Price Summary - Nominal Dollars ........ 182
Exhibit 7-15 High Fuel Case Firm Power Price(1) Summary-Real 1998$/MWh .... 183
Exhibit 7-16 High Fuel Case Firm Power Price(1) Summary-Nominal $/MWh ..... 183
Exhibit 7-17 Low Case Firm Power Price(1) Summary-Real 1998$/MWh .......... 186
Exhibit 7-18 Low Case Firm Power Price(1) Summary-Nominal $/MWh ........... 187
Exhibit 7-19 PPL Generating Stations Regional Revenue and Capacity
Concentration ......................................................... 188
Exhibit 7-20 PPL Generating Stations Regional Revenue and Capacity
Concentration ......................................................... 189
Exhibit 7-21 PPL PJM Generating Stations - Operating Revenues - Base,
Low and High Case ..................................................... 190
Exhibit 7-22 PPL PJM Generating Stations Projected Annual Capacity
Factor (%) - Base Case ................................................ 191
Exhibit 7-23 Base Case Illustrative Summer Peak Supply Curve 2005 - PJM ... 192
Exhibit 7-24 Base Case Illustrative Summer Peak Supply Curve 2015 - PJM ... 193
Exhibit 7-25 PPL NEPOOL Generating Stations Operating Revenue ............. 194
Exhibit 7-26 PPL Station Forecast Base Case Capacity Factors -
NEPOOL (%) - Base Case ................................................ 194
Exhibit 7-27 Base Case Illustrative Summer Peak Supply Curve 2001 - NEPOOL 195
Exhibit 7-28 Base Case Illustrative Summer Peak Supply Curve 2010 - NEPOOL 195
Exhibit 7-29 PPL WSCC Generating Stations - Operating Revenues ............ 196
Exhibit 7-30 PPL WSCC Generating Stations - Projected Annual
Capacity Factors (%) .................................................. 196
Exhibit 7-31 Base Case Illustrative Summer Peak Supply Curve 2005 - Montana 197
Exhibit 7-32 Base Case Illustrative Summer Peak Supply Curve 2015 - Montana 197
Exhibit 7-33 Base Case Illustrative Summer Peak Supply Curve
2005 - Arizona/New Mexico ............................................. 198
- --------------------------------------------------------------------------------
vii [LOGO] ICF CONSULTING
LIST OF EXHIBITS (CONTINUED)
- --------------------------------------------------------------------------------
Page
Exhibit 7-34 Base Case Illustrative Summer Peak Supply Curve
2015 - Arizona/New Mexico ............................................. 199
Exhibit 7-35 Base Case Illustrative Summer Peak Supply Curve
2005 - Pacific Northwest .............................................. 200
Exhibit 7-36 PPL LILCO Generating Stations Operating Revenue .............. 200
Exhibit 7-37 PPL Station Forecast Base Case Capacity Factors -
LILCO (%) - Base Case ................................................. 200
Exhibit 7-38 Base Case Illustrative Summer Peak Supply Curve
2005 - LILCO .......................................................... 201
Exhibit 7-39 PPL ComEd Generating Stations Operating Revenue .............. 201
Exhibit 7-40 PPL Station Forecast Base Case Capacity Factors -
ComEd (%) ............................................................. 201
Exhibit 7-41 Base Case Illustrative Summer Peak Supply Curve 2005 -
ComEd ................................................................. 202
- --------------------------------------------------------------------------------
viii [LOGO] ICF CONSULTING
EXECUTIVE SUMMARY
- --------------------------------------------------------------------------------
Overview
PPL Corporation ("PPL") has requested an independent due diligence
analysis of the PJM, Montana, and other U.S. wholesale power markets in support
of financing related to the newly formed PPL Generating Company. The GenCo will
consist of existing generating units in the PPL fleet, greenfield units
currently under construction, and may also include new units currently in the
initial development stages.
ICF Consulting, Inc. ("ICF") has prepared an independent assessment of (i)
dispatch and revenue projections for selected(1) PPL existing assets in
Pennsylvania, Maine, Connecticut, Montana, and Arizona, (ii) dispatch and
revenue projections for several current development projects being pursued by
PPL in Pennsylvania, Illinois, New York, Arizona, and Washington, (iii) the
competitive and deregulated wholesale power markets in PJM West(2),(3), NEPOOL,
Arizona/New Mexico(4), Montana, Pacific Northwest, New York, PJM East, and
ComEd(5) areas, and (iv) a description of key assumptions and methodology
underlying ICF's power market assessment. This analysis represents a broad
geographic area as the GenCo power generation capacity is 68 percent located in
PJM, 24 percent located in the western grid (WSCC), and the remaining 8 percent
located in other eastern markets.
The results of this analysis will be utilized as a basis for the GenCo's
financial projections. These forecasts incorporate ICF's knowledge of regional
wholesale markets as well as fuel costs, environmental legislation, and all
other factors important to assessing the net operating revenues of the PPL
generating assets. This assessment assumes that all markets are competitive and
that the PPL assets operate as merchant power plants selling into the spot
market(5).
- ----------
1 Units analyzed include the existing facilities owned and the units that
are currently under construction by PPL Corporation. The only exception to
this is several existing turbines in the PJM West market which have not
been analyzed directly. Including these units would increase the portfolio
value presented herein. For a full definition of revenues and costs
discussed in this report, see later discussion.
2 PJM West refers to an ICF computer-modeling region covering the western
part of the current PJM System. This definition roughly corresponds to the
PJM West trading hub. This does not refer to the recently announced PJM
West region which includes Allegheny and Duquesne service territories.
3 PJM = Pennsylvania Jersey Maryland.
4 The PPL generating facilities are located in the state of Arizona which is
part of the Arizona/New Mexico reliability region. All analysis provided
herein is for the entire Arizona/New Mexico market, although the term
"Arizona" may sometimes be used to represent the market.
5 Spot transactions are those lasting less than one year.
- --------------------------------------------------------------------------------
1 [LOGO] ICF CONSULTING
Current U.S. Power Market Conditions
Since deregulation, the wholesale power markets in the U.S. have overall
been very attractive to owners of generating assets. One important driving
factor in this has been the falling reserve margins nationwide (see Exhibit
ES-1). Reserve levels fell in the 1990s due to the combination of strong
electricity demand growth and the near cessation of new capacity additions.
Exhibit ES-1
U.S. Reserve Levels Have Been Falling
- --------------------------------------------------------------------------------
Year U.S. Average Reserve Margin (%)
- --------------------------------------------------------------------------------
1990 20.4
- --------------------------------------------------------------------------------
1991 20.2
- --------------------------------------------------------------------------------
1992 21.2
- --------------------------------------------------------------------------------
1993 17.1
- --------------------------------------------------------------------------------
1994 16.7
- --------------------------------------------------------------------------------
1995 13.2
- --------------------------------------------------------------------------------
1996 14.9
- --------------------------------------------------------------------------------
1997 13.4
- --------------------------------------------------------------------------------
1998 12.0
- --------------------------------------------------------------------------------
1999 10.3
- --------------------------------------------------------------------------------
Source: EEI, Statistical Yearbook of Electric Utility Industry. Based on actual
demand.
Paralleling the fall in reserve margins has been an increase in wholesale
electricity prices (see Exhibit ES-2). For example, PJM wholesale power spot
prices have risen 84 percent between 1996 and 2001 YTD. Likewise, annual average
prices at Palo Verde increased 55 percent per year, or nearly 500 percent total,
between 1996 and 2000. Rising wholesale power prices have reflected not only
scarcity of generation, but also increased reliance on natural gas, higher fuel
prices and tighter environmental regulations.
Exhibit ES-2
PJM Wholesale Electricity Prices (Nominal$/MWh)
- --------------------------------------------------------------------------------
Year PJM Price(1) Palo Verde Price(2)
- --------------------------------------------------------------------------------
1996 25 15
- --------------------------------------------------------------------------------
1997 26 19
- --------------------------------------------------------------------------------
1998 31 23
- --------------------------------------------------------------------------------
1999 43 26
- --------------------------------------------------------------------------------
2000 37 88
- --------------------------------------------------------------------------------
2001 YTD(3) 43 183
- --------------------------------------------------------------------------------
1 Capacity prices are weighted monthly capacity prices form the PJM-ISOs
monthly capacity credit market statistics.
2 Taken from Power Markets Week through April 1998 using reported LMPs plus
reported capacity prices thereafter.
3 2001 YTD is May 2001.
T
- --------------------------------------------------------------------------------
2 [LOGO] ICF CONSULTING
Exhibit ES-3
Location of PPL GenCo Assets
[MAP]
* Indicates planned units.
Diversification and the PPL Portfolio
Roughly 68 percent of the existing and already under construction capacity
owned by the PPL GenCo is located in PJM. However, the existing PPL fleet is
regionally diverse even with this PJM concentration. This diversification
provides the PPL portfolio a physical hedge and lower revenue variance than
either a single asset or a portfolio of assets in a single region. This is
primarily due to its plants located in the western U.S. The purchase of the
Montana Power Company generating assets in 1998 has given PPL a significant
presence in the Western Systems Coordinating Council (WSCC) marketplace (24
percent of total PPL existing/under construction capacity is located in the
Montana, Pacific Northwest, and Arizona wholesale power marketplaces). This
diversity is further expanded when considering the current PPL development
activity into the Midwest and the Northeast.
One key benefit from this regional diversification derives from the lack
of correlation between power prices in different regions of the U.S. Thus, it is
less likely that spot power prices will be low for all plants simultaneously.
ICF did not explicitly estimate the historical degree of diversification
(technically the variance covariance matrix), however, several important
features are highlighted here, especially the WSCC versus PJM diversification,
which we expect to be the most significant source of diversification. Historic
evidence shows little price correlation between WSCC markets and PJM. This is
because the WSCC is extremely transmission isolated from the eastern U.S. in
general, and in particular from PJM. Additionally, the WSCC relies much more on
variable hydroelectricity supplies that are limited in PJM. Lastly, fuel and
environmental markets in the west are distinct from those in the East.
Exhibit ES-4 shows prices for summer on-peak wholesale power supply in
four aggregated U.S. regions. One notable difference in price patterns is seen
between eastern and western markets, especially between the Midwest and the
western U.S. Between 1996 and 1999,
- --------------------------------------------------------------------------------
3 [LOGO] ICF CONSULTING
the western regions saw very little price movement before experiencing the
largest summer wholesale price explosions in U.S. history in 2000. In contrast,
in the eastern U.S. markets, primarily in the Midwest and Southeast, prices
reached extreme highs in 1998 and 1999 before dropping to more moderate levels
in 2000.
Exhibit ES-4
Historical Regional Summer On-Peak Pricing
[GRAPHIC]
Another example of diversification is seen by comparing prices in the
Northeast, including PJM, NEPOOL and New York versus those in the Midwest
(including Illinois). Prices were extremely high in the Midwest in 1998 and 1999
while in the Northeast they were highest in 1999 and 2000. The variation in
prices within the eastern U.S. reflects in part, the significant degree of
electrical transmission isolation between U.S. regions, even within the east.
This lack of electrical transmission capacity in turn creates the conditions for
local and regional supply and demand related differences including differences
in weather, fuel use, fuel prices, plant outages, new plant construction and
entry, and hydrological conditions.
Another measure of the regional diversification benefits built into the
full PPL portfolio is from data on historical power price correlations,
particularly as expressed via correlation coefficients. These coefficients
measure the extent to which changes in prices differ between regions. If the
correlation coefficient is less than one, there are diversification benefits.
The lower the correlation coefficient the greater the benefits. Note, the
correlation average between weekly on-peak regional power price for 1996 to May
21, 2001, were weaker for east to west comparisons and stronger for comparisons
of regions within the eastern or western interconnect. Sample measures of the
correlation coefficients are shown below:
o PJM to Arizona: 0.25
o PJM to NEPOOL: 0.63
o PacNW to Arizona: 0.90
- --------------------------------------------------------------------------------
4 [LOGO] ICF CONSULTING
The low correlation coefficient between PJM and Arizona is especially
indicative of the risk mitigation benefits that could result from the portfolios
spreading of risk across diverse regional operations. Also note that while the
PJM to NEPOOL and the correlation is higher than the representative East/West
correlation, it is not particularly strong at 0.63. This shows that although the
regional PJM pricing may move together with the NEPOOL pricing, there are
significant periods of time in which price movements are not well aligned. The
Arizona and PacNW markets have a much higher correlation.
Exhibit ES-5
Summary of PPL Asset Characteristics by Region
- ---------------------------------------------------------------------------------------------------------------
Parameter PJM NEPOOL Montana AZ/NM PacNW LILCO ComEd TOTAL
- ---------------------------------------------------------------------------------------------------------------
Number of 54 41 39 3 1 1 1 140
Generators(1)
- ---------------------------------------------------------------------------------------------------------------
Total Capacity 9,048 323 1,242 710 1,200 270 540 13,334
(MW)(2)
- ---------------------------------------------------------------------------------------------------------------
Average Heat 9,255 5,961 9,000 7,120 6,753 9,600 9,600 8,926
Rate(3)(Btu/kWh)
- ---------------------------------------------------------------------------------------------------------------
Average Fuel 9.7 19.1 5.5 19.2 19.2 30.4 27.3 10.2
Costs(4) ($/MWh)
- ---------------------------------------------------------------------------------------------------------------
NPV of Dispatch 7,950 272 2,062 471 563 128 263 11,710
Revenues ($000)(5)
- ---------------------------------------------------------------------------------------------------------------
NPV of Dispatch 879 842 1,660 663 469 474 487 878
Revenues
(1998$/kW)(5)
- ---------------------------------------------------------------------------------------------------------------
Note: Includes existing units and any firmly planned capacity additions. Values
calculated for PPL owned portions only.
1 Number of physical generating units at the PPL assets analyzed herein. PPL
owns additional peaking capacity in PJM.
2 PPL owned portion of 2005 capacity. Includes planned capacity uprates.
3 Weighted by generation for 2005. HHV. Full Load. Hydroelectric units have
zero heat rate.
4 Represents projections for 2005, weighted by generation.
5 NPV is calculated using an 11.2 percent real discount rate. Does not
include taxes, debt or some cost items such as new capital additions.
Includes revenue, short-run variable costs and estimated non-fuel O&M.
Note, the diversification benefits in power plant portfolios are also due
in part to the size of the portfolio. In this regard, we note that the PPL
portfolio is fairly large. Not counting units being developed, it represents 133
generators and over 10,000 MW. Thus, unexpected plant outages and O&M costs are
likely to be smoother year-to-year than if only one unit or a small,
undiversified portfolio was involved.
The portfolio of PPL power plants is very well diversified in terms of
fuel, plant type, and usage (i.e., peaking versus intermediate, cycling versus
baseload). The portfolio is weighted however to baseload and/or low variable
cost generating units which further decreases some features of potential revenue
variance. In particular, when evaluating both the existing and currently planned
development projects:
o Coal - Coal accounts for 33 percent of the PPL portfolio capacity
analyzed here. In comparison to the U.S., coal accounts for 41
percent of the capacity mix. PPL coal capacity is located in both
the eastern and western U.S., and is baseload capacity due to low
fuel costs.
- --------------------------------------------------------------------------------
5 [LOGO] ICF CONSULTING
>
o Nuclear - Nuclear accounts for 15 percent of the PPL capacity
analyzed here versus 13 percent for the U.S. Again, low fuel costs
cause such units to run in baseload mode.
o Hydro - Hydroelectric power plants account for 7 percent of PPL
capacity analyzed versus 10 percent for the U.S.
o Natural Gas/Oil Units - Natural gas/oil-fired units currently
account for 42 percent of the PPL capacity versus 29 percent for the
U.S. Over time, additional gas-fired units are added to the PPL
portfolio increasing the percentage of gas-fired units to 45
percent. This is consistent with the rising U.S. percentage of gas
units.
Exhibit ES-6
Summary of PPL Asset Characteristics by Capacity Type
- --------------------------------------------------------------------------------
Combined Oil/Gas Peaking
Parameter Hydro Nuclear Coal Cycle Steam Units Total
- --------------------------------------------------------------------------------
Number of 102 2 14 4 3 15 140
Generators(1)
- --------------------------------------------------------------------------------
Total Capacity(2) 892 2,057 4,420 2,072 1,712 2,181 13,334
- --------------------------------------------------------------------------------
Average Heat Rate(3) 0 10,481 9,657 6,859 10,745 9,618 8,926
- --------------------------------------------------------------------------------
Average Fuel Costs(4) 0.0 5.8 9.6 19.4 0.0 29.5 10.2
- --------------------------------------------------------------------------------
NPV of Dispatch 1,400 2,169 4,929 1,114 1,009 1,088 11,710
Revenues ($000)(5)
- --------------------------------------------------------------------------------
NPV of Dispatch
Revenues 1,569 1,054 1,115 538 589 499 878
(1998$/kW)(5)
- --------------------------------------------------------------------------------
Note: Includes existing units, units currently under construction, and any
firmly planned capacity additions. Values calculated for PPL owned portions
only.
1 Number of physical generating units at the PPL assets analyzed herein. PPL
owns additional peaking capacity in PJM.
2 Includes planned capacity uprates.
3 Weighted by generation for 2005.
4 Represents projections for 2005, weighted by generation.
5 NPV is calculated using an 11.2 percent real discount rate and does not
include taxes, debt, or some cost items such as new capital additions.
Includes revenues, short-run variable costs and estimated non-fuel O&M.
Conclusions
The principal findings of this analysis are as follows:
o The PPL portfolio is a well-diversified portfolio, both in
generating unit types and in their geographical location. This
diversity is beneficial in that it lowers net revenue variance.
Note, the forecasts contained within address some, but not all
aspects of these diversification benefits, and hence, may understate
them.
o The majority of the capacity in the PPL portfolio is located in
western PJM. This market is advantageous relative to some others
because the plants have good access to multiple markets. There is
strong access to the higher priced eastern and southern PJM markets,
and there is also good access to the very large Midwest power
markets. Western PJM is currently only a single "wheel" from the
ECAR market, a Midwestern market with a history of very high price
spikes.
- --------------------------------------------------------------------------------
6 [LOGO] ICF CONSULTING
o The western PJM access to multiple markets provides benefits not
accounted for in this study in any scenario. For example, it is less
likely that many markets will be simultaneously overbuilt than a
single region.
o The largest portion of PPL's PJM fleet, the coal assets, is
comprised of relatively low cost generation resources that are
expected to benefit from competition with higher cost natural gas
power plants. This is especially true since natural gas-fired power
plants will increasingly be on the units on the "margin" setting
power prices.
o Current price highs in the gas and oil markets strongly benefit the
PPL baseload nuclear, coal, and hydro units which are the majority
of the PPL portfolio, even with the currently higher spot market
coal prices.
o Even under the low electricity price market scenario in which there
are sustained very low natural gas prices, the PJM baseload units
perform well financially based on revenues from operation.
o In PJM and in Montana, coal unit performance is additionally
enhanced by their proximity to coal fields, giving them good access
to relatively low-cost coal.
o In NEPOOL, PPL's largest amount of capacity is hydroelectric units.
The hydro capacity reflects the PPL acquisition of the former Bangor
Hydro assets. These units are expected to continue to earn
significant energy profits as natural gas-fired units become even
more predominant in the market.
o Despite the large number of capacity additions in NEPOOL, the market
projections remain robust, particularly in the very near-term.
However, developments in Quebec could create downward price pressure
in the 2002 to 2004 period which are not captured in this study.
o PPL has added gas-fired combined cycle capacity in Arizona. The
Griffith combined cycle unit will be available this summer (2001)
when conditions in the California market are expected to result in
roughly 260 hours of blackouts in the summer according to the just
released NERC Summer Reliability Assessment. With its strong
interconnection to California, the Arizona market prices are
expected to mimic the expected rise in value in California.
o PPL will expand its position into PJM East, New York, ComEd,
Arizona, and the Pacific Northwest. Each of these markets represent
advantageous locations for the planned gas-fired facilities.
The Modeling Approach
The wholesale power market price forecasts in this report were generated
using ICF's IPM(TM) power model. IPM(TM) is a simulation model projecting
wholesale market power prices based on an analysis of the engineering economic
fundamentals relating to supply and demand. All major factors affecting
wholesale electricity prices are addressed in the simulation including detailed
modeling of existing and planned units, with careful consideration of fuel
prices, environmental allowance prices and compliance costs, and operating
constraints.
Based on looking at the supply/demand balance in the context of the
various factors discussed above, IPM(TM) projects the hourly spot price of
electric energy within a larger wholesale power market. Unlike other dispatch
models, IPM(TM) also projects the annual "pure" capacity price (i.e., the annual
revenue associated with price spikes during the super peak demand periods). The
model also projects plant generation levels (i.e., dispatch), merchant
- --------------------------------------------------------------------------------
7 [LOGO] ICF CONSULTING
power plant revenues and costs, new power plant construction, mothballing,
retirements, retrofitting, upgrades, fuel consumption, and inter-regional
transmission flows. The model determines appropriate production, and therefore
production costs and prices, using a linear programming optimization routine
with dynamic effects (i.e., it looks ahead at future years and simultaneously
evaluates decisions over specified years).
ICF's IPM(TM) power model is widely accepted. The model has been used in
hundreds of price and plant valuation assignments for developers over the course
of ICF's nearly 30 years of generation sector experience. IPM(TM) is widely
accepted by rating agencies and investment banking institutions. The model has
been used extensively in litigation and administrative regulatory settings
including the largest stranded cost case in U.S. history. The model has been
used on behalf of both public and private sector clients. IPM(TM) and earlier
versions are the only tools used by the U.S. federal government over the last
twenty-five years for detailed analysis of the impacts of air pollution
regulations on the wholesale power industry. Lastly, the model has been used
extensively internationally and by industry-wide entities such as EPRI, EEI, and
CRIEPI (Japan's EPRI).
To account for the influences of interconnections with neighboring
systems, we have also modeled almost the entire North American power industry
including the Eastern Interconnect subdivided into approximately twenty-five
regional or sub-regional markets, and the western grid separated into nine
regions. Therefore, the market price forecast, plant dispatch profile, and
operating costs and revenues for the GenCo are part of a single, internally
consistent analysis that considers all interactions across the grids in all
years. Further detail on the markets modeled and the approach is provided in
Chapter Five.
Elements of the Forecast
The key assumptions used for the model runs can be considered in four
broad categories:
o Demand and Capacity - electricity demand, new power plant builds,
and costs for future new plants
o Market Structure and Modeling Approach - market structure,
deregulation aspects, regional transmission organizations
o Energy - fuel prices, new plant heat rates, plant availability, and
variable non-fuel O&M
o Environmental Regulations - air quality measures.
A summary is provided in Exhibit ES-7.
- --------------------------------------------------------------------------------
8 [LOGO] ICF CONSULTING
Exhibit ES-7
Summary of Key Modeling Assumptions - Base Case
- -------------------------------------------------------------------------------------------------------------
Region
Parameter ----------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- -------------------------------------------------------------------------------------------------------------
2001 Peak Demand (MW)(1),(2)
2001 Net Internal Demand 52,410 23,517 21,926 4,610 2,123 17,571 28,091
(MW)(1),(2)
Annual Peak Growth 50,484 23,517 20,171 4,610 2,091 17,571 27,682
2001 - 2005 (%)
2006 - 2010 (%) 2.4 2.1 2.2 1.7 2.3 3.8 2.3
2011 - 2020 (%) 2.1 1.9 2.0 1.5 2.2 3.6 2.2
1.9 1.8 1.9 1.3 2.0 3.5 2.0
- -------------------------------------------------------------------------------------------------------------
2001 Weather-Normalized
Net Energy for Load
(GWh)(1), (2)
Annual Peak Growth 264,153 125,333 94,882 19,407 13,065 89,613 192,012
2001 - 2005 (%)
2006 - 2010 (%) 2.2 1.9 2.3 1.6 2.0 3.9 2.0
2011 - 2020 (%) 2.1 1.8 2.1 1.5 1.9 3.7 1.9
1.9 1.7 1.9 1.3 1.8 3.6 1.8
- -------------------------------------------------------------------------------------------------------------
Planning Reserve Margin
(%)
2001 19.0 18.0 15.0 18.0 15.0 15.0 15.0
2005 17.8 18.0 15.0 18.0 15.0 15.0 15.0
2010 15.0 17.0 14.0 18.0 15.0 15.0 15.0
2015 15.0 15.0 14.0 14.0 15.0 15.0 15.0
2020 15.0 15.0 13.0 14.0 15.0 15.0 15.0
- -------------------------------------------------------------------------------------------------------------
Capacity additions that are already completed or have
begun construction are explicitly included in the
modeling as "Firm Builds". Beyond this, the model
New Builds optimizes construction of new capacity internally to
ensure that reserve requirements are achieved. The
capacity added by the model is determined by selecting
the most economical power plant technology option
available.
- -------------------------------------------------------------------------------------------------------------
Firmly Planned Builds (MW)
2000 752 3,536 1,618 0 0 140 0
2001 1,212 934 746 0 0 3,830 1,018
2002+ 3,436 2,435 1,970 270 0 2,300 2,213
TOTAL 7,136 6,905 4,334 270 0 6,270 3,231
- -------------------------------------------------------------------------------------------------------------
Economic Regulation Deregulated
- -------------------------------------------------------------------------------------------------------------
Power Market Structure Perfectly Competitive, Perfectly Efficient
- -------------------------------------------------------------------------------------------------------------
Transaction Type Spot
- -------------------------------------------------------------------------------------------------------------
Expectations Rational with foresight
- -------------------------------------------------------------------------------------------------------------
Economic retirement option provided after 2002 based on requirement to
Economic Retirements meet annual fixed O&M costs; available for select nuclear and fossil units
- -------------------------------------------------------------------------------------------------------------
Environmental Regulations Already promulgated only
- -------------------------------------------------------------------------------------------------------------
Demand own Price
Elasticity Implicit in demand growth projection only
- -------------------------------------------------------------------------------------------------------------
Fuel Market Transaction Spot
Type
- -------------------------------------------------------------------------------------------------------------
Transmission Tariff Less "pancaking" than currently prevails, e.g., Midwest
Structure
- -------------------------------------------------------------------------------------------------------------
New Transmission Lines None
- -------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
9 [LOGO] ICF CONSULTING
Exhibit ES-7
Summary of Key Modeling Assumptions - Base Case (continued)
- ---------------------------------------------------------------------------------------------------------
Region
Parameter ---------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZNM
- ---------------------------------------------------------------------------------------------------------
New Unit Characteristics Combustion Combined Cycles and LM6000s
All-In Capital Costs --------- ------------------- -------
(1998$/kW)(3) Turbines Cogeneration
-------- ------------
2001 375 617 497
2005 375 617 497
2010 357 587 473
2015 339 559 450
2020 323 531 428
Levelized(4) 2001- 363 598 482
2020
Fixed O%M
(1998$/kW-yr) 13.5 20.0/21.5 14.8
- ---------------------------------------------------------------------------------------------------------
Capital Charge Rate for
New Units (%)(5)
Combusion Turbines 14.8 15.7 15.8 16.5 15.5 15.2
Combined Cycle 12.9 13.9 14.0 14.7 13.7 13.5
LM6000 14.8 15.7 15.8 16.5 15.5 15.2
- ---------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
10 [LOGO] ICF CONSULTING
Exhibit ES-7
Summary of Key Modeling Assumptions - Base Case (continued)
- ----------------------------------------------------------------------------------------------
Region
Parameter ----------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZNM
- ----------------------------------------------------------------------------------------------
New Power Plant Combined Cycle Cogeneration Combustion LM6000
Builds -------------- ------------ ---------- ------
Heat Rate Turbine
(Btu/kWh) -------
2001 6,893 6,393 10,858 9,538
2005 6,753 6,253 10,671 9,374
2010 6,583 6,083 10,443 9,173
2015 6,417 5,917 10,219 8,976
2020 6,255 5,755 10,000 8,784
Levelized(4) 2001-
2020 6,680 6,180 10,572 9,287
Variable O&M
(1998$/MWh) 1.1 1.2 2.3 1.1
Minimum Turndown 0 0 0 0
Availability (%) 91.9 91.7 90.7 91.7
- ----------------------------------------------------------------------------------------------
Existing Power Plant
Availability(6) Turndown %
Constraints (%)
Coal Steam 84 - 88 40
Oil/Gas 87 - 91 25
Steam
- ----------------------------------------------------------------------------------------------
Variable O&M
(1998$/MWh) Range(7)
Combined Cycle 0.98 - 7.11
Combustion
Turbine 0.81 - 5.91
Oil/Gas Steam 1.3 - 9.4
Unscrubbed Coal 1.0 - 11.3
Scrubbed Coal 2.1 - 12.3
- ----------------------------------------------------------------------------------------------
Annual Average
Nuclear Capacity
Factor (%)
2001 86.3 81.7 85.1 80.5 66.0
2005 86.4 81.7 86.0 N/A N/A 80.5 66.0
2010 85.7 81.7 86.3 80.5 66.0
2015 85.0 81.6 85.1 80.5 66.0
2020 86.4 85.0 84.9 80.5 66.0
- ----------------------------------------------------------------------------------------------
Nuclear Retirements End of operating license
- ----------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
11 [LOGO] ICF CONSULTING
Exhibit ES-7
Summary of Key Modeling Assumptions - Base Case (continued)
- ---------------------------------------------------------------------------------------------------------
Delivered Fuel prices (1998$/MMBtu)
Parameter ----------------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ---------------------------------------------------------------------------------------------------------
Natural Gas(5)
2001 5.33 5.22 5.13 5.52 5.09 5.34 5.00
2005 3.03 2.91 2.84 3.21 2.73 2.80 2.71
2010 3.16 3.03 2.94 3.38 2.63 2.90 2.82
2015 3.35 3.08 2.83 3.63 2.28 2.54 2.48
2020 3.39 3.19 2.74 3.67 2.11 2.38 2.04
Levelized
Average
(2001-2020) 3.73 3.59 3.46 3.95 3.23 3.43 3.27
- ---------------------------------------------------------------------------------------------------------
Residual 1%
Oil(5)
2001 3.75 3.76 4.56 4.26 4.72 4.18 4.72
2005 3.27 3.27 3.95 3.77 4.11 3.56 4.11
2010 3.41 3.41 3.95 3.91 4.11 3.57 4.11
2015 3.54 3.54 3.95 4.04 4.11 3.57 4.11
2020 3.54 3.54 3.95 4.04 4.11 3.57 4.11
Levelized(4)
Average
(2001-2020) 3.53 3.53 4.17 4.04 4.33 3.78 4.33
- ---------------------------------------------------------------------------------------------------------
Distillate Oil(5)
2001 5.23 5.29 5.19 5.93 5.81 5.16 5.81
2005 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2010 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2015 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2020 4.52 4.57 4.49 5.21 5.11 4.45 5.11
Levelized(4)
Average
(2001-2020) 4.77 4.83 4.74 5.48 5.37 4.70 5.37
- ---------------------------------------------------------------------------------------------------------
Coal(5),(8)
2001 1.23 1.27 0.64 0.55 0.94 0.64
2005 0.92 0.97 0.27 0.21 0.72 0.27
2010 0.96 0.94 0.27 0.22 0.70 0.27
2015 0.94 0.89 0.27 N/A 0.22 0.71 0.27
2020 0.92 0.84 0.28 0.23 0.73 0.28
Levelized(4)
Average
(2001-2020) 1.02 1.04 0.36 0.30 0.78 0.36
- ---------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
12 [LOGO] ICF CONSULTING
Exhibit ES-7
Summary of Key Modeling Assumptions - Base Case (continued)
- ---------------------------------------------------------------------------------------------------------------
Treatment
Parameter ----------------------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ---------------------------------------------------------------------------------------------------------------
Non-Utility Generators
(MW)
Dispatchable 2,744 2,167 159 0 82 671
Non- N/A
Dispatachable 1,273 671 150 43 3 555
Total 4,017 2,838 309 43 85 1,226
- ---------------------------------------------------------------------------------------------------------------
SO(2) Regulation Phase II Acid Rain - no tightening of current legislation assumed
- ---------------------------------------------------------------------------------------------------------------
NO(x) Regulation NO(x) OTR, AND NO(x) SIP Call modeled
- ---------------------------------------------------------------------------------------------------------------
CO(2) Regulation Not Modeled
- ---------------------------------------------------------------------------------------------------------------
Mercury Regulations Not Modeled
- ---------------------------------------------------------------------------------------------------------------
Allowance Prices SO(2) NO(x)(9)
(1998$/ton) ----- --------
2001 206 958
2005 252 1,921
2010 352 2,681
2015 580 3,572
2020 580 3,572
- ---------------------------------------------------------------------------------------------------------------
Import Capability(10) (GW) Export Capability(10)(GW)
-------------------------- -------------------------
PJM 21.8 23.9
NEPOOL 1.5 1.9
ComEd 5.4 7.7
LILCO 2.1 2.3
Montana 2.4 3.4
Arizona/New Mexico 4.2 9.4
PacNW 11.4 12.3
- ---------------------------------------------------------------------------------------------------------------
1 To account for historical forecast error, ICF has reviewed NERC's demand
forecasts and determined the average forecast error percentages over
roughly the last 20 years. ICF's current forecasts are based on the NERC
ES&D 2000 vintage projection and adjusted for historical forecast error.
2 Values shown are weather normalized.
3 Adjusted for summer regional conditions.
4 Assumes an 11.2 percent real discount rate.
5 Weighted average by sub-regional peak demand for PJM East, South, and West
shown.
6 Range of values.
7 Variable O&M is determined by the total operation of the unit, it is
inversely correlated with capacity factor.
8 Representative minemouth price. The price of the most frequently burned
coals are shown.
9 2001-2002 OTR allowance prices are assumed to be $1,000 based on current
market activity.
10 Includes inter-regional and intra-regional.
Although we believe the representation of the market to be reasonable and
realistic, several element of our forecast are conservative in nature.
o Perfect Competition - This analysis assumes the market for
generation is perfectly competitive. Since no market is truly
perfectly competitive, this tends to understate prices, all else
equal.
o Disequilibrium Shortages - This analysis does not consider the
potential for shortages of generation capacity to affect power
prices, even in 2001 and even in the WSCC. In contrast, this
analysis does consider the implications of potential excess
capacity; if there were excess capacity power prices would be
depressed in this modeling exercise.
- --------------------------------------------------------------------------------
13 [LOGO] ICF CONSULTING
o Fuel Prices - Fossil fuel prices are projected to fall from current levels
over the next few years. This decreases the revenues of baseload nuclear
units, a key part of the GenCo portfolio.
o Transactions - All merchant plants can only sell spot, and hence, cannot
hedge against volatility. This is in spite of the fact that hedging is
common as indicated by existing GenCo power sales arrangements.
o Ancillary Services - This analysis assumes no extra ancillary services
revenues are available beyond the opportunity cost of revenues lost from
passing up regular power supply in the course of ancillary service
provision. This could be conservative for some units.
o Demand Growth - Demand will grow at less than historical levels for much
of the forecast horizon, thereby lowering the need for new capacity.
o New Plant Costs and Performance - ICF assumes new plant costs decrease in
real terms in later years while their thermal efficiencies improve. Thus,
future competitors have better performance characteristics.
Fuel Prices
Natural Gas Prices are a critical assumption to the development of a power
price forecast. In the Base Case, natural gas prices average about $3.11/MMBtu
(see ES-8, simple average real 1998 dollars). This is below current (i.e.,
through May 2001) gas prices. However, average Henry Hub price in from 1995
through 2000 was $2.69/MMBtu (real 1998$) - very close to the ICF long-term
average forecast. In our forecast, Henry Hub prices commence at relatively high
levels consistent with recent market and then decline over time slightly before
leveling out. This reflects a similar pattern as embedded in our projection for
oil prices. Commodity and transportation prices for natural gas vary with demand
on a seasonal basis in accordance with our forecasts and historical trends -
higher prices in the winter than in other seasons.
Exhibit ES-8
Natural Gas Prices - Henry Hub - Real Dollars (1998$/MMBtu)
- --------------------------------------------------------------------------------
Period Base Case Low Case High Case(1)
- --------------------------------------------------------------------------------
2001 4.99 4.36 5.53
- --------------------------------------------------------------------------------
2002 3.68 3.22 4.08
- --------------------------------------------------------------------------------
2003 3.09 2.62 3.64
- --------------------------------------------------------------------------------
2004 3.01 2.45 3.63
- --------------------------------------------------------------------------------
2005 2.68 2.28 3.34
- --------------------------------------------------------------------------------
2010 2.75 1.96 3.52
- --------------------------------------------------------------------------------
2015 2.64 2.09 3.45
- --------------------------------------------------------------------------------
2020 2.54 2.04 3.23
- --------------------------------------------------------------------------------
Levelized(2) 3.16 2.59 3.84
- --------------------------------------------------------------------------------
1 The High Case forecast incorporates NYMEX futures prices for 2001 through
2004.
For the years 2005 through 2020, the ICF High Gas Forecast is used.
2 Levelized used an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
14 [LOGO] ICF CONSULTING
Regional Wholesale Power Price Forecasts - Regional Summary
Over time, Base Case firm unit contingent all-hours bundled power prices
decline in real terms while nominal prices increase. One key driver of the power
price trend is the expected gas price. The ICF gas price forecast is very strong
in the near-term and expected to decline fairly quickly to reach equilibrium
market levels by 2005. This pattern dominates the near-term power pricing which
is highly correlated to the gas price. Similarly, the price of oil and coal is
also considered to be strong in the very near-term declining to equilibrium
levels by 2005.
Gas prices increasingly impact the power price as new gas-fired units
begin to set the margin in more hours. The ICF real gas price for Henry hub
declines slowly over time. This in combination with a trend for technological
improvements at new power plants (higher efficiencies over time) contributes to
the ICF expectation of decreasing real power prices.
Regional Base Case firm power prices vary from $29/MWh to $45/MWh (real
1998$) across the regions analyzed. Note, firm power prices reflect both the
competitive electric energy price earned from dispatch and the capacity or
volatility component associated with the reliability of megawatts. LILCO
represents the high end, reflecting the limited transmission capabilities and
higher fuel costs within the market. ComEd represents the low end of the pricing
range, reflecting the strong transmission interconnects with neighboring areas
and the strong number of baseload units currently located in the area and
throughout MAIN.
Sensitivity Case Results
High Case results increase on a show an increase in levelized firm power
prices of between 8 and 14 percent. The largest effect is realized in NEPOOL
where we have forecast a 13.8 percent increase in levelized firm power prices
between 2001 and 2020. The increase of 7.8 percent in Montana is the lowest of
all regions analyzed. In general we see the exaggerated impact in NEPOOL which
is most dependent on oil and gas in while coal dominated regions are less
impacted due to the nature of the sensitivity case.
The Low Case results show a similar relationship across regions to the
Base Case. The greatest differences occur in the WSCC regions while ComEd has
the smallest percent impact in average pricing.
Exhibit ES-9
Summary of ICF Firm Power Price Forecasts by Region and Case -
All Hours - Real Dollars
- --------------------------------------------------------------------------------
Levelized Firm Power Price 2001 - 2020 (1998$/MWh)
Region -----------------------------------------------------------------
Base Case High Fuel Case Low Case
- --------------------------------------------------------------------------------
PJM West 33.8 36.6 28.7
- --------------------------------------------------------------------------------
NEPOOL 40.0 45.5 34.2
- --------------------------------------------------------------------------------
Montana 36.1 38.9 29.4
- --------------------------------------------------------------------------------
Arizona 37.9 41.2 30.9
- --------------------------------------------------------------------------------
PacNW 40.0 43.4 32.9
- --------------------------------------------------------------------------------
LILCO 45.0 49.3 37.8
- --------------------------------------------------------------------------------
ComEd 28.9 32.4 25.0
- --------------------------------------------------------------------------------
Note: Levelized prices calculated using an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
15 [LOGO] ICF CONSULTING
ICF forecasts only moderate seasonal correlations in the competitive
electrical energy component of prices (for a detailed discussion of the
paralytic term, competitive electrical energy price, one of two components of
firm prices, see later chapter). This reflects selected regional demand and
supply differences Note that this is not a result of comprehensive "Monte Carlo"
simulation nor is this an exploration of correlations related to the second
component of prices, the price spike/capacity price revenues component.
Exhibit ES-10
Summary of ICF Base Case Firm Power Price Forecasts by Region - Real
[GRAPHIC]
- --------------------------------------------------------------------------------
16 [LOGO] ICF CONSULTING
Exhibit ES-11
Summary of ICF Base Case Firm Power Price Forecasts by Region - Nominal
[GRAPHIC]
In the Base Case prices decrease from 2002 to 2003 due to decreasing coal
and gas prices (as the fuel markets gradually return to equilibrium from their
current tight market conditions) and as the capacity market softens modestly.
Thereafter, in real, inflation-adjusted terms, firm prices increase through
2010. Note, in nominal terms, prices increase even more significantly due to
general inflation. The rise in real prices through 2010 largely reflects
increasing electrical energy prices driven by demand growth as coal is being
displaced by natural gas as the marginal price setting fuel source. Beyond 2010,
firm real prices plateau for a period in real terms and then decrease despite
increasing gas use in the system over the same period. Increased efficiencies,
decreasing costs of new units, and decreasing natural gas prices over time tend
to offset demand growth increases.
Power Plant Dispatch
The baseload PPL units continue to perform very well over the forecast
horizon. Coal, nuclear, and hydro units dispatch to full availability for almost
all units. Dispatch on the combined cycle units begins at relatively high levels
but begins to tail off in the very long term as the units most compete
against newer, more efficient gas-fired competitors. Although the hours
dispatched declines over time, the combined cycle units tend to make a higher
hourly return in hours dispatched in the long-term. Note that the peaking and
oil/gas steam units have relatively low dispatch as compared to the baseload
units, however, theses units serve the purpose of being readily available in
high load periods, and as such, tend to earn very high margins through the
capacity payment when dispatched.
- --------------------------------------------------------------------------------
17 [LOGO] ICF CONSULTING
Exhibit ES-12
Projected Capacity Factor of PPL Generating Stations by Region and Capacity
Type - Base Case 2005
- -------------------------------------------------------------------------------------------------------
Combined Oil/Gas
Region Capacity Coal Nuclear Hydro Cycle Peakers(1) Steam(2)
- -------------------------------------------------------------------------------------------------------
PJM 9,048 68 88 40 55 13 0
- -------------------------------------------------------------------------------------------------------
NEPOOL 323 N/A N/A 63 N/A 24 0
- -------------------------------------------------------------------------------------------------------
Montana 1,242 87 N/A 56 N/A N/A N/A
- -------------------------------------------------------------------------------------------------------
Arizona 710 N/A N/A N/A 74 5 N/A
- -------------------------------------------------------------------------------------------------------
PacNW 1,200 N/A N/A N/A 87 N/A N/A
- -------------------------------------------------------------------------------------------------------
LILCO 270 N/A N/A N/A N/A 24 N/A
- -------------------------------------------------------------------------------------------------------
ComEd 540 N/A N/A N/A N/A 10 N/A
- -------------------------------------------------------------------------------------------------------
Capacity
Weighted N/A 71 88 52 76 13 0
Average
- -------------------------------------------------------------------------------------------------------
Notes: Simple average of the annual capacity weighted average capacity factor by
type for years unit operating; N/A = Not Applicable
1 Includes turbines, diesel units, and jet engines.
2 Oil/gas steam units are expected to operate in hotter than average summer
periods and/or periods of greater than average outages. The associated
super peak revenues are included in the analysis although the capacity
factor level does not reflect the hours dispatched.
As seen in the following exhibits, the PPL operating fleet represents a
well-mixed portfolio of baseload, mid-level, and peaking units with emphasis on
baseload.
Exhibit ES-13
Base Case Illustrative Summer Peak Supply Curve 2005 - PJM
[GRAPHIC]
Note: Zero cost generation includes hydro capacity, non-dispatachable units, and
portions of units operating on minimum turndown.
- --------------------------------------------------------------------------------
18 [LOGO] ICF CONSULTING
The majority of the PPL fleet is located in PJM and is interspersed well
through the regional supply curve. The largest amount of capacity (nuclear,
hydro, and much of the coal) is concentrated in the bottom half of the supply
curve. These units dispatch well before the marginal unit in most hours, and
hence, earn substantial energy profits in addition to revenues from price spikes
and/or capacity sales. Note that units that may dispatch only for peaking
purposes, i.e., to capture capacity price revenues are not shown in the supply
curves presented herein in that their value is not obtained from dispatch for
energy markets.
Exhibit ES-14
Base Case Illustrative Winter Peak Supply Curve 2005 - PJM
[GRAPHIC]
Note: Zero cost generation includes hydro capacity, non-dispatchable units, and
portions of units operating on minimum turndown.
PJM is affected by NO(x) regulations in the summer months beginning in
2003. For units with NO(x) emissions, an adder to normal operating costs are
seen in the summer to account for NO(x) allowance purchases. The adders are
reflected only in summer months. To indicate the relative differences in these
periods, we show both a summer and winter supply curve.
- --------------------------------------------------------------------------------
19 [LOGO] ICF CONSULTING
Exhibit ES-15
Base Case Illustrative Summer Peak Supply Curve 2005 - NEPOOL
[GRAPHIC]
Note: Zero cost generation includes hydro capacity, non-dispatchable units, and
portions of units operating on minimum turndown.
In NEPOOL, PPL owns hydro units which dispatch to full availability. A
small amount of the hydro capacity has the capability to dispatch for peak and
thus optimize earnings. Additionally, PPL owns a portion of the Wyman 4 oil/gas
steam unit and owns the Wallingford generating station. Both units dispatch in
super-peak hours capturing capacity price volatility. In addition, the
Wallingford unit operates in mid-level load periods and performs well against
existing gas and oil/steam units.
- --------------------------------------------------------------------------------
20 [LOGO] ICF CONSULTING
Exhibit ES-16
Base Case Illustrative Winter Peak Supply Curve 2005 - NEPOOL
Note: Zero cost generation includes hydro capacity, non-dispatchable units, and
portions
[GRAPH]
of units operating on minimum turndown.
As in PJM, NEPOOL is also affected by NO(x) emissions constraints in the
summer period. Exhibit ES-16 shows a representative dispatch curve for the
winter peak. Given the limited amount of coal in NEPOOL, there is little change
in dispatch order although variable cost pricing at gas-fired units is impacted
by seasonal fuel prices.
- --------------------------------------------------------------------------------
21 [LOGO] ICF CONSULTING
Exhibit ES-17
Base Case Illustrative Summer Peak Supply Curve 2005 - Montana
[GRAPHIC]
Note: Zero cost generation includes hydro capacity, non-dispatchable
units, and portions of units operating on minimum turndown.
The PPL Montana assets form the majority of the existing capacity in the
WSCC region. The coal units in Montana are very low cost and supply power to
meet load both internally to Montana and externally (e.g., to California via the
Pacific Northwest). Similarly, the PPL hydro units are well situated to the
transmission interconnects and can easily supply generation to neighboring
regions. Montana is well interconnected to the Northwest Power Pool and tends to
export large amounts of power to other regions.
Nearly 95 percent of the fully operational capacity in the PPL fleet is
held within PJM, NEPOOL, and Montana. With the planned expansion units, this
percentage will be reduced to 80 percent. Given the predominance of capacity
located in the three referenced markets, the Executive Summary focuses on these
markets when discussing dispatch. For description of the LILCo, PacNW,
Arizona/New Mexico and ComEd markets, refer to Chapter Seven.
PPL Fleet Revenue Assessment
The PPL fleet is forecast to perform well throughout the life of the
study. On a NPV basis, the total portfolio generates in the Base Case of about
12 billion dollars. Roughly 77 percent of the PPL capacity is in PJM and Montana
- - these units account for roughly 86 percent
- --------------------------------------------------------------------------------
22 [LOGO] ICF CONSULTING
of the net operating revenues(6) for the fleet. The Base Case reflects the most
likely market conditions given the expectations on individual market parameters
such as demand growth and fuel prices.
In the High Fuel Case, the natural gas and prices are examined under an
extended near-term high price situation. Since the High Fuel Price Case is
reflective of only fuel prices, it does not capture the full upside potential
for power prices. The High Fuel Case is reflective of the current trends in the
gas markets and incorporates near-term the market outlook as reflected in the
futures strip prices. Results for the high case show earnings of almost 13
billion dollars (1998$), an increase of 10 percent over the Base Case. PJM shows
the largest increase in revenues associated with the High Fuel Case sensitivity,
an increase of 13.8 percent. This increase is driven by increased energy margin
due to higher gas prices realized by the low cost PPL coal assets in PJM.
Similarly we see significant additional revenues in NEPOOL under this scenario.
The baseload NEPOOL and PJM units see significant increase in value when
competing against unit operating on high cost gas. While this case is considered
an upside case note that it is a very conservative representation of the upside
in that we examine only the effects of near term gas prices being consistent
with current market outlook.
In the Low Case, a range of variables are set to levels likely to lower
power prices including natural gas and oil prices, electricity demand growth and
new power plant characteristics. The Low Case also represents the potential for
a number of parameters to be at low levels and captures an 80-90 percent
confidence interval. Low Case results show a drop in revenues to 8.5 billion for
the PPL fleet, a decrease of 26.8 percent when compared with the Base Case.
Again we see that PJM and NEPOOL are the regions most affected by this
Sensitivity Case. Note that the Low Case includes downside potential in fuel,
equipment and demand, and as such both the energy and capacity revenues of the
units are affected. In contrast, the High Fuel Case examines the upside
potential through high gas prices and only affects energy prices in the near
term.
Exhibit ES-18
NPV of PPL Generating Stations by Region and Case
- --------------------------------------------------------------------------------------
NPV (Millions of Dollars (1998$)(2),(3)
Capacity ------------------------------------------------
Region (MW)(1) Base High Fuel Low Case
- --------------------------------------------------------------------------------------
PJM 9,048 7,950 9,044 5,599
- --------------------------------------------------------------------------------------
NEPOOL 323 272 296 208
- --------------------------------------------------------------------------------------
Montana 1,242 2,062 2,272 1,601
- --------------------------------------------------------------------------------------
Arizona 710 471 442 352
- --------------------------------------------------------------------------------------
PacNW 1,200 563 514 498
- --------------------------------------------------------------------------------------
LILCO 270 128 127 105
- --------------------------------------------------------------------------------------
ComEd 540 263 278 205
- --------------------------------------------------------------------------------------
Total 13,334 11,710 12,973 8,568
- --------------------------------------------------------------------------------------
1 2005 PPL owned and analyzed capacity is shown.
2 NPV calculated using an 11.2 percent real discount rate.
3 Does not include taxes, debt, and some cost items such as new capital
additions. Includes revenue, short run variable costs and FERC Form 1
non-fuel O&M.
- ----------
6 Based on separate ICF pro formas that do not include taxes, debt payments
and some fixed O&M cost items, but rather focus on revenue and short-run
variable costs.
- --------------------------------------------------------------------------------
23 [LOGO] ICF CONSULTING
The majority of the portfolio's capacity has a very high value per
kilowatt of generating capacity. Coal, nuclear, and hydro units have greater NPV
value per kilowatt than gas- or oil-fired units due to their larger energy
revenues. As mentioned previously, coal units make up the majority of the PPL
fleet. Note that the coal units are forecast to earn 42 percent of the total PPL
fleet revenues through 2020.
In the High Fuel and Low Cases, coal units continue to dominate the
earnings, contributing over 40 percent of the total value in both cases. Nuclear
units have the next highest contribution at nearly 20 percent in both cases.
These baseloaded units also experience the greatest change in expected earnings
by capacity type.
The High Fuel Case is profitable to most baseloaded units given that units
on alternate fuels such as coal or nuclear do not experience a change in cost,
but do receive higher revenues in hours when gas units set the energy price. The
PPL gas-fired units revenues are not significantly affected at the higher gas
prices as they are generally competing with other gas-fired units experiencing
similar cost increase.
In the Low Case, the value of the overall portfolio drops by roughly 27
percent. The largest impact is felt at the steam units, with drops of 29 percent
at the coal, 31 percent at the nuclear, and 28 percent at the oil/gas steam. The
combined cycle and hydro units have a lower rate of decline at roughly 20
percent.
Expected profits by type are relatively proportional to the actual
capacity mix. Coal units at 33 percent of total capacity have a slightly higher
percent of total revenues at 42 percent; similarly nuclear units earn a slightly
higher percent of total earnings than accounted for in the capacity mix at 19
percent versus 15 percent, respectively. Hydro units also have a higher revenue
contribution at 12 percent of total earnings versus 7 percent of capacity.
Exhibit ES-19
NPV of PPL Generating Stations by Capacity Type and Case
- ----------------------------------------------------------------------------------------------------
NPV Millions of Dollars (1998$)(2),(3)
Parameter Capacity ---------------------------------------------------------------------
(MW)(1) Base High Fuel Low Case
- ----------------------------------------------------------------------------------------------------
Hydro 892 1,400 (1,570) 1,525 (1,709) 1,122 (1,257)
- ----------------------------------------------------------------------------------------------------
Coal 4,420 4,929 (1,115) 5,679 (1,285) 3,485 (789)
- ----------------------------------------------------------------------------------------------------
Nuclear 2,057 2,169 (1,054) 2,532 (1,231) 1,491 (725)
- ----------------------------------------------------------------------------------------------------
Combined Cycle 2,072 1,114 (538) 1,070 (516) 899 (434)
- ----------------------------------------------------------------------------------------------------
Peakers 2,181 1,088 (499) 1,106 (507) 841 (386)
- ----------------------------------------------------------------------------------------------------
Oil/Gas Steam 1,712 1,009 (589) 1,061 (620) 729 (426)
- ----------------------------------------------------------------------------------------------------
Total/Average(4) 13,334 11,710 (878) 12,973 (973) 8,568 (643)
- ----------------------------------------------------------------------------------------------------
Note: ( ) shows values on a dollar per kilowatt basis.
1 2005 PPL owned and analyzed capacity is shown.
2 NPV calculated using an 11.2 percent real discount rate.
3 Does not include taxes, debt, or some cost items such as new capital
additions. Includes revenue, short run variable costs and FERC Form 1
non-fuel O&M.
4 NPV Millions of Dollars shown as total for all capacity; dollar per
kilowatt shown as weighted average by capacity.
- --------------------------------------------------------------------------------
24 [LOGO] ICF CONSULTING
Organization of Report
The remainder of this report is organized as follows:
o Chapter One - Historical Pricing and Market Structure in PJM,
NEPOOL, New York, MAIN, Montana, AZNM, and PacNW - Provides insight
into the key markets for the PPL portfolio through discussion of the
historical market pricing, the relationship between the regions, and
the general market structure.
o Chapter Two - The PJM Regional Wholesale Market - This chapter
describes the merchant power plant marketplace with emphasis on
liquidity, price discovery and competitiveness.
o Chapter Three - The WSCC Regional Wholesale Markets - Relevant
aspects of the Montana, Arizona/New Mexico, PacNW, and overall WSCC
markets are discussed. Assessments of the supply and demand balance,
the transmission capabilities, and the generating capabilities are
provided.
o Chapter Four - The NEPOOL Regional Wholesale Market - An overview of
the NEPOOL market is provided.
o Chapter Five - Modeling Approach and Input Assumptions - This
chapter provides an in-depth discussion of input assumptions and
approach for the analysis of merchant dispatch revenues and the
forward market conditions.
o Chapter Six - PPL Unit Level Assumptions and Summary Results -
Further detail of the PPL portfolio is provided.
o Chapter Seven - Detailed Market Price and Fleet Operating Revenue
Results - This chapter presents ICF forecasts of forward market
conditions, dispatch and revenues for the GenCo operating as a
merchant plant supplementing the discussion in the Executive Summary
on such issues as energy and capacity price components, peak/off
peak spread, and capacity expansion.
- --------------------------------------------------------------------------------
25 [LOGO] ICF CONSULTING
CHAPTER ONE
HISTORICAL PRICING AND MARKET STRUCTURE IN PJM, NEPOOL,
NY, MAIN, MONTANA, AZNM, AND PACNW
- --------------------------------------------------------------------------------
Introduction
This chapter discusses historical regional power pricing and the
marketplace structures under deregulation for the four power markets in which
PPL operates units. The purposes of this chapter are several-fold. First, we
compare historical average prices with our Base Case forecast prices. Second, we
discuss historical year-to-year price variability across regions. Third, we
review prices in greater detail region-by-region. This review pays extra
attention to PJM in light of its importance in the portfolio. And finally, we
discuss the regional market structures under a deregulated environment.
ICF does not directly use historical prices to forecast future prices.
Rather, ICF assesses the supply and demand fundamentals in each year. This is
done in part due to the lack of historical data, but is largely driven by the
fact that future conditions will be different than past conditions (e.g., new
environmental regulations, new power plants). Nonetheless, historical prices are
useful perspectives on ICF forecasts.
Forecast versus Historical
When compared with recent historical averages, the ICF Base Case regional
pricing forecasts are on average below the average prices seen in 2000 and thus
far in 2001. This is because 2000 and 2001 year-to-date western U.S. prices have
been so high. In contrast, our forecast is modestly above average historical
prices for the 1996 to 2000 period. In large part, the change in forecast is
driven by increased coal use and the associated environmental costs. The OTR and
SIP Call NO(x) program is not reflected in most of the historical pricing,
whereas it's directly incorporated in the forecast.
Year 2001 forecast prices in the East reflect that the PJM and NEPOOL
markets are expected to be very tight on capacity given the anticipated capacity
additions available for the summer peak. Price levels in 2000 were lower than
anticipated due to relatively moderate summer weather conditions. Also,
increased reliance on oil and natural gas and strong forecasts of fuel prices
cause prices in the east to be strong in our forecast relative to history.
Forecast prices in the West reflect equilibrium markets and do not capture
extreme prices associated with market shortages as seen in 2000 and to date in
2001.
- --------------------------------------------------------------------------------
26 [LOGO] ICF CONSULTING
Exhibit 1-1
Near-Term Base Case Firm Power Price Forecast versus Historical (Real 1998$/MWh)
- ------------------------------------------------------------------------------------------
Base
Case
ICF
YTD Forecast
Region 1996 1997 1998 1999 2000 2001(2) 2001
- ------------------------------------------------------------------------------------------
PJM West(1) 21.4 21.2 18.0 26.0 37.0 44.8 39.6
- ------------------------------------------------------------------------------------------
NEPOOL 29.5 30.6 26.6 33.5 51.5 58.1 59.7
- ------------------------------------------------------------------------------------------
Montana COB 14.0 15.8 23.3 25.4 129.9 274.5 62.1
- ------------------------------------------------------------------------------------------
Arizona/
Palo Verde 16.1 19.9 23.3 25.0 108.8 203.7 61.1
- ------------------------------------------------------------------------------------------
PacNW 15.7 16.0 23.3 26.1 129.3 275.7 69.3
- ------------------------------------------------------------------------------------------
Simple Average 19.3 20.7 22.8 27.2 91.3 171.3 58.3
- ------------------------------------------------------------------------------------------
1 In 1996 and 1997, PJM was a single index. The PJM index splits in April
1998, the 1998 value is an average of the PJM and PJM West indices. The
1999 and 2000 values are shown for the PJM West index.
2 As of May 8, 2001.
Source: Power Markets Week, ICF. Does not include ICAP price in NEPOOL & PJM.
Exhibit 1-2
Historical versus Forecast Prices - (Real 1998$/MWh)
- --------------------------------------------------------------------------------
Base Case Forecast -
Average of Annual Prices ICF Levelized Average
Region 1996-2001 YTD(1) 2001 - 2020
- --------------------------------------------------------------------------------
PJM West 28.0 33.8
- --------------------------------------------------------------------------------
NEPOOL 38.3 40.4
- --------------------------------------------------------------------------------
Montana COB 80.5 35.8
- --------------------------------------------------------------------------------
Arizona/Palo Verde 66.1 37.7
- --------------------------------------------------------------------------------
PacNW 81.0 39.7
- --------------------------------------------------------------------------------
Simple Average 58.8 37.5
- --------------------------------------------------------------------------------
Note: Does not include ICAP price which could increase PJM and NEPOOL prices by
$1 to $3/MWh.
1 As of May 8, 2001.
Source: Power Markets Week, ICF
The ICF long-term scenario forecasts are representative of likely outcomes
around the expected market prices. As compared to the average historical from
1996 through 2000, the real prices in the Downside Case are about 11 percent
below the historical, while the High Fuel Price Case are 30 percent higher.
- --------------------------------------------------------------------------------
27 [LOGO] ICF CONSULTING
Exhibit 1-3
Forecast versus Annual Historical - All-Hours Firm Prices -
Real Dollars (1998$/MWh)
- ---------------------------------------------------------------------------------------------------
Downside 1996-2001 YTD(1) Historical Annual Prices High Fuel
Case ICF ---------------------------------------------- Price Case
Forecast ICF Forecast
2001 - 2020 2001 - 2020
Levelized Levelized
Region Average Lowest Year Average Highest Year Average
- ---------------------------------------------------------------------------------------------------
PJM West 28.7 44.8 36.7
- ---------------------------------------------------------------------------------------------------
NEPOOL 34.2 26.6 38.3 58.1 45.5
- ---------------------------------------------------------------------------------------------------
Montana/COB 29.4 14.0 80.5 274.5 31.1
- ---------------------------------------------------------------------------------------------------
Arizona/Palo
Verde 30.9 16.1 66.1 203.7 31.4
- ---------------------------------------------------------------------------------------------------
PacNW 32.9 15.7 81.0 275.7 33.9
- ---------------------------------------------------------------------------------------------------
Simple
Average 31.2 19.3 58.8 171.3 35.7
- ---------------------------------------------------------------------------------------------------
1 As of May 21, 2001.
Source: Power Markets Week, ICF. Does not include ICAP price in NEPOOL & PJM.
Cross-Regional Power Price Comparisons
The geographic diversification of the PPL units result in a physical hedge
against regional price risk given that price diversity exists across the
regions. Exhibit 1-4 outlines recent historical on-peak summer pricing across
geographic regions. As many influences on price spikes are not forecastable,
summer spikes will necessarily be unpredictable and dispersed. The PPL fleet is
well positioned to take advantage of these diversities, especially those between
the eastern and western U.S.
Exhibit 1-4
Historical Regional Summer On-Peak Prices
[GRAPH]
- --------------------------------------------------------------------------------
28 [LOGO] ICF CONSULTING
Exhibit 1-5
1996 Real Wholesale Electric Energy Prices
[GRAPHIC]
Sources: System Lambda FERC 714 filings, Power Markets Week Indices.
ICF-Back-casting, State avoided cost filings.
Note: Prices are representative of actual regional prices in 1996.
1996 was the first year pricing information became available from
published market indices, however, most markets were not very liquid or did not
have full year values available. Exhibit 1-5 reflects historical system
lambdas(7) marginal system energy costs or reported price indices for 1996. In
periods of excess, the system lambda or energy price would be reflective of the
full firm value of power. In 1996, most markets did not experience shortage of
capacity and as such, the values reported as firm power price indices are
directly comparable to reported system lambdas to a large degree. The energy
price is based on the actual variable costs of operating the marginal unit in
any given hour. Traditionally, regions with large amounts of baseload capacity
have had low energy prices while those relying to a larger degree on oil or gas
steam and turbine units have had high costs.
PJM, NEPOOL, and New York have historically had relatively high costs of
producing energy largely due to their higher degree of oil and gas use. In 1996,
NEPOOL had the highest reported energy prices in the country due to its
dependence on oil and gas on the margin. PJM was only slightly below that of
NEPOOL. Due to its dependency on more costly coal and oil/gas steam units on the
margin, PJM was the fourth most expensive region out of eighteen.
In contrast, the Montana, Pacific Northwest, and Arizona/New Mexico
regions which rely much more heavily on coal and hydro units (particularly in
the northwest) had very low electric energy prices. The Montana pricing is
reflected in the regional average for the Pacific Northwest in Exhibit 1-5.
These low firm wholesale electricity prices also reflected low natural gas
prices and high hydroelectric supply conditions.
- ----------
7 System lambdas are a measure of the short-run variable costs of
incremental or marginal electrical energy production, and thus, correspond
to the electrical energy price concept.
- --------------------------------------------------------------------------------
29 [LOGO] ICF CONSULTING
>
Exhibit 1-6
1998 On-Peak Power Markets Week Index of Regional Power Prices
[GRAPHIC]
Source: Power Markets Week
Regional power prices in both the summer of 1997 and the summer of 1998
were higher than prices in 1996, particularly due to summer on-peak price
increases in the Midwest. Exhibit 1-6 highlights on-peak spot prices which we
tend to think of as representative of firm prices (i.e., bundled energy and
capacity.) The Midwest price spikes were driven by capacity shortages created by
a lack of capacity additions in the late 1980s and early 1990s. PJM, NEPOOL and
western U.S. prices (e.g., COB/NOV, Palo Verde) did not experience the same
spikes. As a result, historical pricing patterns were nearly reversed with the
Midwest becoming the highest priced regions and PJM and NEPOOL much more
moderately priced. The PJM regional price was influenced by the Midwest prices
to the extent that PJM was able to sell capacity into the Midwest markets. Note
that both PJM and NEPOOL enforce relatively high reserve margins (about 19
percent for all load serving entities) which contributed to limiting the
magnitude of price spikes. Even so, PJM, in particular, is affected by
developments in VACAR and ECAR where there are no enforceable reserve margins to
suppress price volatility and no similar reserve margins exist in the West.
As shown, the WSCC regions remained very low cost in 1998. Similarly,
NEPOOL prices were low relative to most of the rest of the country. This is
somewhat surprising as NEPOOL had historically been expected to be a high-priced
marketplace, particularly for electrical energy, due to the dominance of
expensive oil/gas steam units in the supply mix and high delivered fuel prices.
This is explained by NEPOOL's isolation from markets experiencing shortages and
also by the very low market prices for oil.
- --------------------------------------------------------------------------------
30 [LOGO] ICF CONSULTING
>
Exhibit 1-7
2000 On-Peak Power Markets Week Index of Regional Power Prices
[GRAPHIC]
Source: Power Markets Week
In 1999, WSCC remained quite stable when the Eastern markets, especially
the Midwest and Southeast U.S., were experiencing high degrees of volatility.
However, in 2000, when the Eastern markets were on average calm, the WSCC
markets reached overall highs. Exhibit 1-7 demonstrates the relative change in
regional price positions experienced to date in the year 2000. This switch was
largely due to the demand growth and capacity needs in the California
marketplace which impacted many other regions. More specifically in the WSCC,
continuing demand growth, a return to normal weather, a lower than normal summer
hydro season, lower than typical unit availability, and practically no capacity
additions finally resulted in price spikes.
Regional Price Discussion
Regional marketplaces can vary in structure of products and organization
as shown in Exhibit 1-8. The ICF firm power price represents a bundling of the
energy and capacity price components. The ICF methodology is directly correlated
to varying regional marketplace structures. A full breakout of energy and
capacity market prices is presented in the discussion of modeling approach in
Chapter Five.
- --------------------------------------------------------------------------------
31 [LOGO] ICF CONSULTING
Exhibit 1-8
Comparison of Northeastern and California Markets
- --------------------------------------------------------------------------------
PJM NEPOOL NYPP California
------------------------------------------------------
Products Operational
- --------------------------------------------------------------------------------
Energy Yes Yes Yes Yes
- --------------------------------------------------------------------------------
Yes. Auction
Market
ICAP Yes terminated in Yes No
August 2000.
Bilateral trades
still exist
- --------------------------------------------------------------------------------
Ancillary Services No, tied to Yes Yes Yes
Energy Market
- --------------------------------------------------------------------------------
Transmission
Congestion/Transmission Yes No Yes Yes
Rights
- --------------------------------------------------------------------------------
Historical PJM Power Prices
In 1996 and 1997, PJM prices were relatively muted. In 1998, PJM
experienced more spikes even though it failed to experience large price spikes
similar to those in the neighboring Midwest. This was due to several factors
including transmission congestion blocking movement of power westward, and less
capacity shortages. In 1999, PJM prices spiked to much higher levels indicating
a tighter capacity market and very hot weather. In 2000 relatively mild summer
conditions helped to alleviate concerns about market volatility. However,
several spikes did occur during the spring of 2000. To date, the 2001 prices
have been high, largely due to the influence of high gas prices.
Exhibit 1-9
PJM(1) Historical Prices - Nominal $/MWh
--------------------------------------------------------------------
Average Weekly On-Peak
Year Power Prices
--------------------------------------------------------------------
1996 20.7
--------------------------------------------------------------------
1997 20.9
--------------------------------------------------------------------
1998 18.0
--------------------------------------------------------------------
1999 26.4
--------------------------------------------------------------------
2000 38.3
--------------------------------------------------------------------
2001(2) 46.7
--------------------------------------------------------------------
1 The PJM index split in April 1998. The 1996 and 1997 values
represent the PJM index, 1998 represents an average of the PJM
and PJMW index, and 1999 and 2000 YTD represent only the PJMW
index.
2 As of May 8, 2001.
Source: Power Markets Week.
- --------------------------------------------------------------------------------
32 [LOGO] ICF CONSULTING
Exhibit 1-10
PJM Weekly Peak Indices - Power Markets Week
[GRAPHIC]
Exhibits 1-9 and 1-10 summarize Power Markets Week (PMW) on-peak spot
prices including the 1998 through 2000 summer prices. Power Markets Week is
generally representative of firm prices (i.e., bundled energy and capacity).
This evidence indicates that firm prices observed in the PJM marketplace are
slightly below average relative to prices observed throughout the U.S. This was
somewhat surprising in light of our earlier discussion and the dominance of
expensive oil/gas steam units in the supply mix and high delivered fuel prices.
This was explained by the lack of market tightness in the summer of 1998
relative to the Midwest. As is discussed later in this study, this also
reflected relatively low capacity prices embodied in the overall firm price.
On April 1, 1998, PJM began to use locational marginal pricing (LMP) as
the basis for spot energy prices and congestion management. Under this method,
prices for over 1,700 nodes within PJM are derived. Because of the large number
of nodes and the necessity to develop stable price signals for trades, PJM has
developed average prices at three hubs -- the Western Interface Hub, Eastern
Hub, and Western Hub. Even so, PJM is the only one of the four regions examined
with such a system. That, in combination with the importance of PJM, indicates
that extra consideration of the historical PJM prices is in order.
- --------------------------------------------------------------------------------
33 [LOGO] ICF CONSULTING
Exhibit 1-11
PJM Locational Marginal Prices 1999-2000
- --------------------------------------------------------------------------------
Western
PJM Eastern Interface Western
- --------------------------------------------------------------------------------
1999 Average 28.36 28.33 27.96 28.02
Peak 41.36 42.13 40.62 40.70
Off-Peak 17.88 18.10 17.76 17.79
- --------------------------------------------------------------------------------
2000 Average 28.49 30.74 27.49 27.72
Peak 37.05 40.19 35.54 35.96
Off-Peak 19.86 21.20 19.36 19.40
- --------------------------------------------------------------------------------
2001 Average(1) 33.72 38.43 33.91 33.82
Peak 44.53 43.15 38.49 38.44
Off-Peak 23.66 34.17 29.78 29.66
- --------------------------------------------------------------------------------
1999-2001(1)
Average 28.63 32.50 29.79 29.85
Peak 40.98 41.82 38.22 38.37
Off-Peak 20.41 24.49 22.30 22.28
- --------------------------------------------------------------------------------
Note: PJM Zone is our aggregate of all load buses only. The other hubs consist
of load buses and 500 kV load generation.
1 2001 YTD numbers through April 30, 2001.
Source: PJM/ISO.
Review of the time series of average LMP Hub prices in PJM indicates that
for the majority of the year the LMPs within each hub do not generally diverge,
and when they do, the degree of difference is not sizeable. For example, the
maximum difference between hub LMPs is never more than $3/MWh and the average
difference is $0.4/MWh. When LMPs did diverge, LMPs in PJM East were higher than
PJM West and South. The maximum difference between zonal LMPs was as much as
$48/MWh, but averaged substantially less.
In addition to the LMP markets, PJM has a structured capacity market. The
Capacity Credit Market ("CCM") was proposed by PJM in October 1998 in response
to the needs of the Pennsylvania retail access program. FERC approved the use of
this market in January 1999. Exhibit 1-12 shows historical transactions in the
capacity market.
- --------------------------------------------------------------------------------
34 [LOGO] ICF CONSULTING
Exhibit 1-12
Capacity Trading at PJM - Daily Trading
[GRAPH]
Source: PJM ISO as of June 11, 2001
Two capacity markets exist in PJM. The first trades monthly and the second
trades for the next day. Since June of 1999, capacity credits have been based on
unforced capacity obligations specified in the Reliability Assurance Agreement.
Market clearing capacity credits from monthly independent trading periods have
been approximately $25/kW-yr. The days ahead market generally has been trading
at one-fifth or uses of monthly market clearing prices.
- --------------------------------------------------------------------------------
35 [LOGO] ICF CONSULTING
Exhibit 1-13
PJM Power Prices vs. Fuel Costs
[GRAPH]
Sources: Power Markets Week, Natural Gas Week, Platt's Oilgram
The above figure shows time series of fuel and power prices. They confirm
the fact that in off-peak seasons prior to April 1998, average peak power prices
are partially explained by trends in natural gas prices. When the June through
August peak periods are removed, the correlation between natural gas and the PJM
composite average peak prices is 0.46. Correlation with the minimum of delivered
natural gas and 1% residual fuel is 0.42. The correlation between 1 percent NY
residual and off-peak season average peak prices is 0.36.
Annual average PJM peak indices and Henry Hub prices do not indicate much
linkage. Even though gas prices were falling, power prices rose in 1997. This is
because the pure capacity component increased as the markets tightened and
historically high peak demand conditions were experienced. PJM average annual
prices increased further in 1998 at the same time that average Henry Hub gas
prices decreased.
Historical Prices - NEPOOL
By 1999 and 2000 especially, NEPOOL wholesale prices had become more
highly volatile. In July and August of 1999, due to a heat wave experienced
across New England and neighboring regions, wholesale prices surged to all-time
NEPOOL high in the peak hours, but remained average during off-peak hours.
Similarly, price spikes were seen in early spring 2000. Despite mild summer
weather conditions in 2000, prices on average were at some of the highest levels
seen since prices were recorded in 1996. The YTD average on-peak price through
October 2000 was near $50/MWh. This was in part due to very high oil and gas
prices.
- --------------------------------------------------------------------------------
36 [LOGO] ICF CONSULTING
Exhibit 1-14
Historical NEPOOL Prices (Nominal $/MWh)
[GRAPH]
Source: Power Markets Week
As mentioned, the degree of price volatility in NEPOOL has been more
significant in 1999 and 2000 as indicated in Exhibit 1-14. Power shortages and
blackouts were experienced on two occasions in July of 1999 and triggered
compulsive voltage reduction measures by 5 percent across the entire region.
Exhibit 1-15 shows average weekly peak, off peak and all-hours prices
for NEPOOL for 1996 through 2001.
- --------------------------------------------------------------------------------
37 [LOGO] ICF CONSULTING
Exhibit 1-15
Historical NEPOOL Prices (Nominal $/MWh)
- -------------------------------------------------------------------------------------------------
1996--
2001(1) 2001
1996 1997 1998 1999 2000 YTD YTD
- -------------------------------------------------------------------------------------------------
Average Weekly Index 28.6 30.7 26.6 34.0 53.3 60.6 36.5
(on-peak) (nominal $/MWh)
- -------------------------------------------------------------------------------------------------
Average Weekly Index 19.4 22.0 19.7 20.8 33.9 43.4 22.6
(off-peak) (nominal $/MWh)
- -------------------------------------------------------------------------------------------------
Average Weekly Index 23.7 26.1 23.0 27.0 41.2 51.4 27.4
(nominal $/MWh)
- -------------------------------------------------------------------------------------------------
1 As of May 8, 2001.
Source: Power Markets Week.
NEPOOL Capacity Prices
The NEPOOL ICAP market was authorized by FERC in April 1998.
Market-clearing capacity prices at NEPOOL were zero in 1998, which was not
consistent with the bilateral market. Contrary to the ICAP market, the bilateral
installed capacity market was active and prices of the order of $25/kW-yr have
been reported. Recently, NEPOOL eliminated the exchange trading of ICAP.
However, they have left the requirement to have installed capacity to be handled
via the bilateral market.
NEPOOL, like PJM, maintains a high reserve margin of approximately 18
percent which tends to suppress capacity price spikes, all else equal. Reserve
margins may decrease as new more reliable units come on-line. Further, they may
decrease if the ISO's of New England, New York and PJM are able to implement
their memorandum of understanding of August 9th, 1999 to increase inter-tie
capacity.
Historical Prices - NYPP
Similar to the trends seen in NEPOOL during 1999 and 2000 NYPP wholesale
prices have become more highly volatile. In July and August of 1999, due to a
heat wave experienced across the northeast and a tightening capacity situation
in NYPP, wholesale prices peaked in the peak hours. Similarly, price spikes were
seen in early spring 2000. Over the course of the year 2000, prices in NYPP East
and West did not move together. The weekly prices in NYPP East reached levels of
$135/MWh in June of 2000 whereas the highest weekly peak price in NYPP West was
only $63/MWh in May 2000. The higher on-peak prices in NYPP East result
primarily due to the regional isolation of the downstate areas and the local
capacity shortage. In addition, these markets more heavily utilize oil and gas
than do the upstate markets. Despite mild summer weather conditions in 2000,
prices on average were at some of the highest levels seen since prices were
recorded, beginning in 1996. High prices have continued through 2001. The YTD
average on-peak price through May 2001 was $60.4/MWh in NYPP East and $47.0/MWh
in NYPP West. The 2001 prices have been influenced by higher than normal gas
prices.
- --------------------------------------------------------------------------------
38 [LOGO] ICF CONSULTING
Exhibit 1-16
Historical NYPP Prices (Nominal $/MWh)
[GRAPHIC]
Source: Power Markets Week
The degree of price volatility in NYPP has been more significant in 1999
and 2000 as indicated in Exhibit 1-16. Exhibit 1-17 shows average weekly peak
and all-hours prices for NYPP for 1996 through 2001.
Exhibit 1-17
Historical NYPP Prices (Nominal $/MWh)
- --------------------------------------------------------------------------------
1996--
2001(2) 2001
1996(1) 1997 1998 1999 2000 YTD YTD
- --------------------------------------------------------------------------------
Average Weekly On-
Peak Index (nominal 28.2 28.9 36.5 57.3 60.4 39.3
$/MWh) - NYPP East
- ------------------- 24.6 -----------------------------------------------
Average Weekly On-
Peak Index (nominal 24.5 24.6 32.9 40.7 47.0 32.4
$/MWh) - NYPP West
- --------------------------------------------------------------------------------
Average All Hours
(Nominal $/MWh) - 23.5 22.9 27.6 46.4 55.9
NYPP East
- ------------------- 20.0 -----------------------------------------------
Average All-Hours
(Nominal $/MWh) - 19.7 19.8 25.7 32.8 53.9
NYPP West
- --------------------------------------------------------------------------------
1 Prior to March 1997 NYPP prices were not reported separately as NYPP East
and NYPP West.
2 As of May 8, 2001.
Source: Power Markets Week.
- --------------------------------------------------------------------------------
39 [LOGO] ICF CONSULTING
NYPP Capacity Prices
The NYISO ICAP market began on March 29, 2000 after FERC's approval of the
ISO's Services Tariff filing. As established by the NY ISO, each Load Serving
Entity (LSE) must have enough installed capacity to meet peak demand plus
reserve margin. The ISO also assigns locational ICAP requirements. The two
regions within the NY control area currently under locational ICAP requirements
are New York City and Long Island. Within the New York City market, the NYISO
requires that 80 percent of installed capacity be within city limits. The
percent requirement for LILCO is still being determined. Additionally, the ISO
has set a limit of 2,558 MW of capacity located outside of the New York control
area that can be used in the ICAP market. The ISO runs both six month and one
month Installed Capacity auctions to allow for LSEs to procure sufficient
capacity to meet their Installed Capacity requirements. LSEs can also purchase
capacity bilaterally to meet requirements. The ISO has established summer and
winter capability requirements (six months each), each with their own ICAP
requirements. The price caps for ICAP vary by location. First year (through
April 2001) price caps for NY City, LILCO, and all other NYCA zones were $75/kW,
$60/kW, and $52.5/kW, respectively.
NYPP, like PJM, maintains a high reserve margin of approximately 18% which
tends to suppress capacity price spikes, all else equal. Reserve margins may
decrease as new more reliable units come on-line.
Historical Prices - MAIN
In the years prior to the price spikes in the summer of 1998 and 1999,
electrical energy prices in MAIN were historically among the lowest in the
country. The MAIN market had been dominated and oversupplied with low variable
cost coal and nuclear units. These units tended to operate and set prices in
nearly all hours, even at the extreme peak. ComEd has the largest share of
nuclear capacity in its supply mix relative to all other NERC regions in the US.
Additionally, ComEd is situated near local low cost coal resources and also has
excellent access to the low cost Powder River Basin coal.
In the summers of 1998 and 1999, prices were extremely high throughout the
Midwest, especially in Illinois. This was due to seasonally high temperatures
and short supply. In 1998 average weekly peak prices peaked in the week of June
29 at $690/MWh and in 1999 in the week of August 2 at an average price of
$936/MWh (in Southern MAIN). Despite the shortages that drove the price spikes,
no load was involuntarily dropped though voltage reductions did occur and
interruptible customers were asked to shed load.
The exact causes of the price spikes have been investigated by FERC and
others. In our view, price spikes are primarily driven by fundamentals - a tight
supply/demand balance. High peak demand and forced outages of various units in
the region were the impetus behind the tight supply/demand balance.
In contrast to 1998 and 1999, prices in 2000 were lower throughout the
Midwest. The 2000 prices were low in comparison given charges in several of the
fundamental power price drivers. One of the critical elements of change was
represented in the mild weather conditions in the summer of 2000. As a result,
power demand levels were below expected conditions, relieving the pressure on
the supply side for more megawatts.
- --------------------------------------------------------------------------------
40 [LOGO] ICF CONSULTING
Regional Transmission Organizations: MISO and Alliance
The two principal RTOs being considered for most ECAR power plants are the
Midwest ISO (MISO) and the Alliance RTO (Alliance). The regional transmission
organizations expand beyond ECAR and include not only other Midwest regions
(MAIN and MAPP), but also PJM and VACAR. Notably, VEPCo is joining with the
Alliance RTO.
At one point, MISO included Alliant Energy, Ameren, Central Illinois Light
Co. (CILCO), Commonwealth Edison, Hoosier Energy Rural Electric Cooperative,
Illinova Corporation, Louisville Gas & Electric, Madison Gas & Electric, Xcel
Energy (formerly NSP), Southern Illinois Power Cooperative, Southern Indiana Gas
and Electric Cooperative (SIGECO), Wabash Valley Power Association, Wisconsin
Electric Power, WPS Resources Corporation, American Transmission Company, and
Northwestern Wisconsin Electric Company. However, there has been a fragmenting
of the original MISO members and many players have opted to join Alliance, the
competing Midwest proposal.
Alliance RTO members also include AEP, FirstEnergy, Consumers Power,
Virginia Power, and Detroit Edison. In addition, Illinois Power, Ameren and
ComEd have announced their decisions to leave MISO and join Alliance. A map of
the territory covered by Alliance is shown in Exhibit 1-18 and members of MISO
are shown in Exhibit 1-19.
On September 16, 2000 the Alliance RTO submitted a compliance filing in
response to the conditions FERC imposed on orders from December 1999 and May
2000. This filing includes a zonal rate for all transactions that deliver power
within the Alliance and a "postage stamp" rate for all others that deliver power
out of Alliance service territories.
- --------------------------------------------------------------------------------
41 [LOGO] ICF CONSULTING
Exhibit 1-18
Original Membership in the Alliance ISO
[MAP]
Exhibit 1-19
Original Membership in the Midwest ISO
[MAP]
Source: www.midwestiso.com
- --------------------------------------------------------------------------------
42 [LOGO] ICF CONSULTING
The Midwest ISO was conditionally approved by FERC in September 1998 and
Alliance RTO in December 1999. As mentioned, many MISO members have since
indicated intentions to withdraw from MISO and to join Alliance prompting FERC
to intervene to stabilize the situation. This flux had continued for some time
and has expanded to include issues relating to the formation of PJM West. On May
8, 2001, FERC issued an order on a settlement agreement between MISO and
Alliance that included:
o The creation of one super-regional rate area that combines the area
of the Midwest ISO and the Alliance from the Dakotas to the
Mid-Atlantic region;
o An agreement for negotiations among the Midwest ISO, the Alliance
RTO, and PJM for a joint "through-and-out" rate;
o The approval of the withdrawals of Commonwealth Edison, Ameren, and
Illinois Power from the MISO;
o An Inter-RTO Cooperation Agreement between MISO and Alliance that
includes the development of protocols and procedure for coordinated
transmission planning, coordinated security operations,
determination and coordination of available transfer capability
(ATC), a cohesive congestion management approach, independent market
monitoring, one-stop shopping facilitation, compatible real-time
balancing markets, generation interconnection standards and
compatible business practices.
Historical Prices - WSCC
Historically, the Arizona/New Mexico and the Pacific Northwest, including
Montana marketplaces have had relatively low costs of producing energy. The
Pacific Northwest, in particular, has very low variable fuel costs due to the
large amounts of hydro resources combined with significant low variable cost
coal capacity, while Arizona/New Mexico has low variable costs of incremental
output due to the high amount of installed nuclear and coal capacity.
Wholesale prices in the west, as measured by the Power Markets Week Index,
had been low but increasing moderately over the 1996-1999 period, and have been
highly volatile in the summer months of 2000, and have had continued high trends
since. For example, the average year-to-date price in AZ/NM has been nearly
$40/MWh significantly above levels experienced in recent years.
Exhibit 1-20 illustrates the extent of the recent power price volatility
in the West. As indicated, power prices maintained a narrow band through the
late spring of 2000 and have since experienced a much wider band with weekly
prices that vary by nearly $1,000/MWh on the worst occasions.
Exhibit 1-21 provides the trend in the average annual pricing since Power
Markets Week indices began in 1996. Prices were extremely low in the mid-1990s,
demonstrating an upward trend through 1999 before exploding in 2000.
- --------------------------------------------------------------------------------
43 [LOGO] ICF CONSULTING
Exhibit 1-20
Historical On-Peak Prices Indices (Palo Verde/Four Corners/COB/Mid Columbia)
[GRAPH]
Exhibit 1-21
Historical All-Hours Firm Power Prices (Nominal$/MWh)
- ---------------------------------------------------------------------------------------------
Average Weekly Average Weekly Average Weekly Average Weekly
Index (Nominal $) Index (Nominal$) On-Peak Prices On-Peak Prices
Palo Verde & Four COB/Mid- Palo Verde & COB/Mid-
Year Corners Columbia Four Corners Columbia
- ---------------------------------------------------------------------------------------------
1996 15.18 14.22 18.75 15.54
- ---------------------------------------------------------------------------------------------
1997 18.71 16.06 24.91 17.33
- ---------------------------------------------------------------------------------------------
1998 2.70 25.42 28.89 27.06
- ---------------------------------------------------------------------------------------------
1999 25.06 26.84 30.82 28.59
- ---------------------------------------------------------------------------------------------
2000 86.82 126.48 112.85 134.27
- ---------------------------------------------------------------------------------------------
2001 YTD(1) 184.34 276.75 227.23 286.16
- ---------------------------------------------------------------------------------------------
1 As of May 21, 2001.
Source: Power Markets Week.
Market Structure
Retail deregulation is occurring at varying rates across the United
States. Exhibit 1-22 indicates the current status of deregulation. The PPL
operating territories are generally among the most advanced in the United
States. The consequences of retail access on wholesale power prices include:
- --------------------------------------------------------------------------------
44 [LOGO] ICF CONSULTING
o Increased Liquidity and Risk Management. More buyers will be
available to competitors and seeking protection from risks.
o Increased transparency and investor confidence. New entrants,
including both marketers and developers of new generating
facilities, will emerge as confidence in the new market grows.
o Generator Rationalization. Some changes will occur once plants are
out of the rate base. However, major changes may be deferred.
o Demand-Side Effects. Retail customers will likely see higher and
more volatile peak prices and will attempt to reduce their
consumption in response. However, this will be slowly phased-in and
offset by lower retail power prices. On net, our forecast of peak
load growth is lower than historical growth rates.
- --------------------------------------------------------------------------------
45 [LOGO] ICF CONSULTING
Exhibit 1-22
National Deregulation Status as of July 2000
[MAP]
Source: Energy Information Administration
PJM
Within PJM, most states have adopted retail access. The market players are
quickly adapting operations to supply these states appropriately under the
deregulated environment. Among the states in PJM, restructuring in Pennsylvania
has been the most successful in the U.S. in terms of the number of customers
choosing alternative generation suppliers. New Jersey has also had some success
with roughly 13.5 percent of the power load in the state supplied by alternative
retail suppliers since 1999.
Maryland, Delaware, Virginia and DC are at slightly less advanced stages.
Maryland passed restructuring legislation in April 1999. The legislation allows
retail access over a 3-year phase-in period beginning in July 2000 with a third
of customers, another third by 2001, and all by 2002. Customer choice began in
July 2000 for IOU customers, and will start in 2001 for SMECO customers.
Delaware has passed restructuring legislation, with retail competition starting
in October 1999. Phase-in of retail access started in 1999 for large industrial
consumers, in February 2000 - for consumers with over 300 kW demand, and in
August 2000 - for all small consumers. Virginia also passed legislation, calling
for full retail access by 2004, mandatory ISO and PX. Virginia Power started its
first pilot program in 2000.
NEPOOL
The ISO New England is structured as a centralized utility industry
controlled power exchange like the California ISO, NYPP, and PJM. However,
unlike California, NEPOOL has an
- --------------------------------------------------------------------------------
46 [LOGO] ICF CONSULTING
ICAP market, thus making it most similar in some respects to the neighboring PJM
and New York ISOs. The ISO also currently administers several products such as
energy, ICAP and four ancillary service markets, which provide the entire system
requirements for these services.
FERC has recently approved a major market redesign for the New England
ISO, which will be implemented over 2001-2002. The new design elements included:
o Proposed Congestion Management System (CMS) based on locational
marginal prices (similar to the system employed in the NY and PJM
ISOs). Under the CMS, the ISO would establish a two-settlement
system which calls for a day-ahead market and real-time market for
energy and ancillary services.
o A three-part bid mechanism for the ancillary services market. The
more flexible system will allow generators to meet load requirements
at a minimum cost.
o Termination of installed capacity (ICAP) auction market effective
August 2, 2000.
WSCC
The WSCC markets are among the most advanced in enacting legislation
pursuing deregulation of the power markets. In general, the WSCC markets are
also at the forefront in developing institutional frameworks to support market
liquidity. Pricing indices from Power Market Weeks exist for several points in
the WSCC region, mostly concentrated on the coastal markets. Large areas of the
WSCC, such as the Eastern NWPP region and the RMA region, do not have associated
indices.
The AZ/NM market is one of the most liquid in the U.S. and has been
influenced heavily by California markets where deregulation and competition
first occurred in the country.
There are several functioning markets within the AZ/NM region:
o There is a functioning futures market at the Palo Verde switchyard
in Arizona, the most important mechanism in the region for bulk
power sales. Palo Verde is the nations largest nuclear plant and is
close to California, with much of the capacity owned by California
utilities. From this switchyard there is a large volume of business
into California.
o Three spot market price indices are published, including Palo Verde
(Arizona) and Four Corners (New Mexico) and Mead (Nevada).
o There is a significant over-the-counter market. The AZ/NM
marketplace is a net exporter to California, and the California PX
has increased the liquidity and volume of transactions.
Liquidity may vary even for regions with existing price indices. This is
due to the variance in trade volumes across pricing points. For example, the
Palo Verde Index is may be more liquid than the Four Corners Index.
In addition, the California marketplace is more advanced and has a number
of formal interchange systems:
- --------------------------------------------------------------------------------
47 [LOGO] ICF CONSULTING
o The California Independent System Operator (ISO) and wholesale Power
Exchange (PX) began functioning on April 1, 1998. The ISO controls
the high-voltage transmission lines of Pacific Gas & Electric
(PG&E), San Diego Gas & Electric (SDG&E) and Southern California
Edison (SoCalEd).
o The California Power Exchange (PX) provides a marketplace where
trading is facilitated through an electronic auction, establishing a
clearing price for each hour of the following day.
o The California ISO is responsible for system transmission and
reliability, it manages ancillary services and real-time energy
markets to facilitate its system dispatch function. When congestion
occurs on those high-voltage power lines, it also facilitates a
computerized congestion management market where capacity on the
system is bought and sold.
o There are three energy markets in California: the PX Day Ahead
Market, the PX "Day-Of" Market, and the ISO Real-Time Imbalance
Energy Market.
The Montana market is not liquid as such, no reliable pricing information
is available. The best index available is Mid-Columbia. The marketplace pricing
is historically dominated by coal due to the regions close proximity to the
Powder River Basin (PRB). Indeed, northern PRB is in Montana.
In general, the ICF modeling construct captures the full value of the
non-energy products in the capacity price.
- --------------------------------------------------------------------------------
48 [LOGO] ICF CONSULTING
CHAPTER TWO
THE PJM REGIONAL WHOLESALE MARKET
- --------------------------------------------------------------------------------
Introduction
PPL's home territory is the PJM wholesale power marketplace, and hence,
the PPL generation fleet is concentrated there. This fleet is comprised of
several large baseload coal stations, one nuclear station and significant
amounts of hydro and peaking capacity. PPL is expanding its position in PJM with
the ongoing development of new, highly efficient gas-fired combined cycle at
Lower Mount Bethel.
The PPL Facilities are concentrated in western PJM sub-region. However,
the Facilities have extremely good access to the other PJM markets as well as
the marketplaces such as the newly announced PJM West, Alliance RTO, and other
parts of ECAR and MAIN. This provides diversification benefits since it is
unlikely that all markets will be equally priced under all circumstances.
PJM History and Background
The Pennsylvania-New Jersey-Maryland Interconnection (PJM) encompasses all
of New Jersey, Delaware, and the District of Columbia, the majority of Maryland
and Pennsylvania, and the Delmarva Peninsula area of Virginia. PJM also makes up
the Mid-Atlantic Area Council (MAAC), a North American Reliability Council
sub-region. Most recently, two companies APS and Duquesne announced plans to
form an entity PJM West. This would be the most significant change to the size
of the PJM market in decades. As mentioned, the new PJM West is different from,
and geographically further to the West of the ICF PJM west region (see below).
PJM has a unique history; it was the largest centrally dispatched
multi-utility electric system in North America. Historically, PJM operated as a
tight pool with central dispatch under terms of a 1956 Interconnection
Agreement. Under the old PJM pricing structure, utilities offered to buy and
sell electricity at bid and ask prices set equal to costs determined using
government cost accounting systems. PJM used these prices to determine dispatch
and clearing prices. The clearing prices were based on a split-savings approach
which was designed to be fair. It also roughly approximated the outcome of a
situation in which there were only a few players each with some market power.
This history of complex centralized coordination facilitated the rapid
development of a highly integrated regional transmission structure. The old
central dispatch structure was replaced on January 1, 1998 when the PJM
Interconnection became the first operational Independent System Operator (ISO)
in the U.S. The PJM ISO is responsible for the operation and control of the bulk
electric power system throughout PJM.
PJM has traditionally been comprised of 10 major investor owned systems,
one holding company, and several municipal and cooperative system associate
members. The major investor-owned utilities include GPU (with Pennsylvania
Electric, Metropolitan Edison and Jersey Central Power and Light as the main GPU
operating companies), Public Service Electric and Gas (PSE&G), Philadelphia
Electric Company (PECO), Pennsylvania Power and Light (PP&L), Baltimore Gas and
Electric (BG&E), Potomac Electric Power Company (PEPCO), and Conectiv
- --------------------------------------------------------------------------------
49 [LOGO] ICF CONSULTING
(a merger of Atlantic City Electric Company and Delmarva). The service
territories for these utilities and other smaller utilities are illustrated in
Exhibit 2-1.
However, recent or planned power plant divestitures involving three of the
main companies - GPU, Conectiv, and PEPCo - have introduced new players to the
generation sector. GPU has essentially completed its removal from the generation
business through the sales of Oyster Creek Homer City, Three Mile Island,
Seneca, and the remainder of its fossil-fueled and hydroelectric assets. The
assets were acquired by several companies including; Edison Mission Energy,
AmerGen, FirstEnergy, and Sithe. In addition, Conectiv has auctioned 2,200 MW of
nuclear and non-strategic baseload fossil generation assets with assets going to
NRG. PEPCO's auction of it's generation fleet was won by Southern Company in
early 2000.
Exhibit 2-1
Major Participants in PJM - ICF Defined Transmission Regions
[GRAPHIC]
Note: PJM does not include Allegheny or Duquesne who
have recently announced their intention to join the
newly formed PJM West ISO.
Transmission Within PJM
PJM has an extensive internal transmission network and backbone of 500 kV
lines. Nonetheless, PJM experiences some internal transmission constraints.
These constraints can be tight enough to cause internal price differences,
primarily between the West and the East. The predominant power flow has
historically run west to east as capacity deficient PJM East is fed power by
capacity long PJM West.
- --------------------------------------------------------------------------------
50 [LOGO] ICF CONSULTING
Exhibit 2-2
PJM Intra-Regional Transmission
[MAP]
Historically, energy purchases by PJM East had been large from PJM West
and ECAR. More recently, PJM West has had high volumes of energy sales out of
the PJM system into ECAR, especially in the super-peak period. The high prices
obtainable through sales to ECAR are more attractive than sales to PJM East,
resulting in PJM East looking to purchase power from other neighboring regions.
PJM handles internal transmission constraints in a unique manner. In an
attempt to use a market approach to reflect internal PJM transmission
congestion, PJM has implemented what is known as a locational marginal pricing
(LMP) scheme. Under this approach, there is a price for each of PJM's 1,744
nodes. The goal has been to capture all possible price differences in the grid
by determining a separate hourly price for each node. The key is the integration
of a centralized pricing function with transmission constraints.
To date, relatively few large differences have been observed across most
nodes. In fact, PJM itself is moving towards the use of averages. For example,
the PJM West Hub(8) is an average of about 200 nodes and is now the focal point
for trading and proposed future contracts. In this study, these constraints are
modeled by dividing PJM into three principal sub-regions, East, West, and South
as shown in Exhibit 2-2. This is done because it would be impractical to model
1,744 PJM nodes, and other regions, simultaneously for many years. In
particular, it is impractical for the simulation to address expectation about
future years which are needed to address capacity expansion, retirements,
environmental compliance and plant upgrade.
Transmission With Neighboring Regions
PJM is part of the integrated and synchronized Eastern Interconnect in the
U.S. Direct links exist with the surrounding regions of NYPP, VACAR, and ECAR as
shown in Exhibits 2-3 and 2-4. Historically, PJM has been a net importer of low
cost power from ECAR, i.e., coal-by-wire. However, the tight capacity situation
in the Midwest has reversed this position and PJM has recently become a power
exporter to ECAR.
- ----------
8 A subset of the ICF characterization of PJM West.
- --------------------------------------------------------------------------------
51 [LOGO] ICF CONSULTING
Exhibit 2-3
Eastern Interconnect Total Transfer Capability (GW)
[MAP]
Exhibit 2-4
Total Regional Imports and Capability
- ---------------------------------------------------------------------------------------
Approx. Key AC Interconnections
2001 -------------------------
Forecast Total Approx.
Peak Capability Capability Percent of
Region (GW) Region (GW) (GW) Peak (%)
- ---------------------------------------------------------------------------------------
ECAR 3.0
PJM 52 NYPP 0.4 7.0 14
VACAR 3.6
- ---------------------------------------------------------------------------------------
PJM PJM East 2.0
West 13 PJM South 2.4 7.4 57
ECAR 3.0
- ---------------------------------------------------------------------------------------
Source: ICF Consulting.
With the favorable interconnections, it is important to note that even if
one region is temporarily overbuilt, generation owners can take advantage of
transfer capabilities in the well connected portions of the Eastern Interconnect
and export firm capacity to neighboring regions. This reduces the likelihood
that overbuilding of power plants would result in greatly lowered capacity
prices since excess capacity could be absorbed by the neighboring regions to the
extent transmission capabilities exist.
- --------------------------------------------------------------------------------
52 [LOGO] ICF CONSULTING
Capacity and Generation Mix
PJM is long on base load capacity (combination of nuclear and coal
capacity), though PJM has more mid-load and peaking capacity than Midwest and
regions such as ECAR. PJM coal and nuclear generation account for about 85
percent of total generation.
Exhibit 2-5
PJM Capacity and Generation Mix - 1999
Capacity Generation
[PIE CHART] [PIE CHART]
Total Capacity = 57,703 MW Total Generation = 254,370 GWh
Sources: Capacity taken from NERC ES&D 2000; generation derived from EIA Forms
759 and 900. Note, capacity and generation data may not be fully consistent, but
do serve as a proxy for actual regional totals.
Although PJM has less oil/gas steam capacity than New York or New England,
the oil/gas units do set the marginal price in some hours. In addition, since
these units are located primarily in Eastern PJM, they tend to increase LMPs in
this sub-region during periods of congestion.
PJM also has a relatively heavy reliance on generation from Independent
Power Producers (IPPs), accounting for about 8 percent of capacity and almost 10
percent of the total generation. Although IPPs are spread throughout PJM, about
two-thirds of the total are located in and supply power to Eastern PJM.
The capacity mixes of PJM East and PJM West differ significantly. In PJM
West coal makes up a larger percentage of the total capacity mix, approximately
60 percent. Conversely, generation capacity in PJM East is more predominantly
oil/gas steam. Further, PJM West has direct access to coal imports from
neighboring ECAR and PJM-South has direct access to coal power in VACAR. PJM
East does not have access to similarly cheap coal imports, except from PJM West.
This creates a potentially interesting congestion consequence - an inability to
displace PJM East oil/gas power with coal power from PJM West.
Supply and Demand Balance
PJM is a summer peaking system with approximately 52 GW of peak demand.
This is roughly comparable in size to ERCOT and California and more than twice
the size of NEPOOL. Exhibit 2-6 summarizes the historical trend in peak demand
and energy in PJM.
- --------------------------------------------------------------------------------
53 [LOGO] ICF CONSULTING
Exhibit 2-6
Historical Peak Demand and Energy Growth Rates in PJM
- -----------------------------------------------------------------------------------------------
Peak Demand Energy Demand Interruptible
Year (MW) (GWh) Load(1) (MW)
- -----------------------------------------------------------------------------------------------
2000 52,350 261,499(2) 1,881
- -----------------------------------------------------------------------------------------------
1999 51,645 255,741 2,181
- -----------------------------------------------------------------------------------------------
1998 48,397 249,247 2,298
- -----------------------------------------------------------------------------------------------
1997 49,406 243,649 2,239
- -----------------------------------------------------------------------------------------------
1996 44,302 243,328 2,014
- -----------------------------------------------------------------------------------------------
1995 48,524 242,797 1,970
- -----------------------------------------------------------------------------------------------
1994 45,992 238,061 1,845
- -----------------------------------------------------------------------------------------------
1993 46,429 235,664 1,571
- -----------------------------------------------------------------------------------------------
1992 43,622 225,906 1,449
- -----------------------------------------------------------------------------------------------
1991 45,870 228,236 1,388
- -----------------------------------------------------------------------------------------------
1990 42,544 220,772 1,184
- -----------------------------------------------------------------------------------------------
1989 41,556 223,642 934
- -----------------------------------------------------------------------------------------------
1988 43,073 218,383 929
- -----------------------------------------------------------------------------------------------
1987 40,526 206,756 N/A
- -----------------------------------------------------------------------------------------------
1986 37,527 197,056 N/A
- -----------------------------------------------------------------------------------------------
Historical Annual Average Growth Rates (%)
- -----------------------------------------------------------------------------------------------
1990 - 2000 2.1 1.7
- -----------------------------------------------------------------------------------------------
1989 - 1999 2.2 1.4
- -----------------------------------------------------------------------------------------------
1988 - 1998 1.2 1.3
- -----------------------------------------------------------------------------------------------
1987 - 1997 2.0 1.7
- -----------------------------------------------------------------------------------------------
1986 - 1996 1.7 2.1
- -----------------------------------------------------------------------------------------------
Simple Average
- -----------------------------------------------------------------------------------------------
1 Interruptible load is estimated value from NERC ES&D first year forecast.
2 Peak and energy values from PJM Load Forecast Report, February 2001.
Source: NERC ES&D, unless otherwise noted.
PJM load and energy requirements have been growing at a lower rate
relative to the U.S. average - on average between 1.5 and 2.0 percent over the
last ten to fifteen years. Similar to other regions, very little capacity had
been added since the early 1990s until most recently. It is very close to being
in demand and supply balance (see Exhibit 2-7). Interest from developers within
PJM had lagged behind that in neighboring regions. However, PJM has recently
received considerable interest in terms of potential new construction.
Approximately 7 GW of new capacity has been announced, although only
approximately 15 percent or so of these announcements have actually materialized
in terms of permitting and actual construction.
- --------------------------------------------------------------------------------
54 [LOGO] ICF CONSULTING
Exhibit 2-7
Forecast PJM Supply and Demand Balance, 2001
- --------------------------------------------------------------------------------
Demand for Gigawatts Supply of Gigawatts
- --------------------------------------------------------------------------------
Peak Demand(1) 52.4 Existing Capacity(2) 58.8
- --------------------------------------------------------------------------------
Interruptible/
Controllable Load(1) 1.9 Net Firm Exports(2) 0
- --------------------------------------------------------------------------------
Net Peak Demand 50.5 Inoperable Capacity(1) 0
- --------------------------------------------------------------------------------
Reserve Margin 19.0%(2) 9.6 New Builds(3) 1.5
- --------------------------------------------------------------------------------
Total Need 60.1 Total Supply 60.3
- --------------------------------------------------------------------------------
Expected Reserve Margin (%): 19.4
- --------------------------------------------------------------------------------
Surplus Gigawatts: 0.2
- --------------------------------------------------------------------------------
1 Source: 2000 PJM Load Forecast; ICF assumed growth rate.
2 ICF Estimate
3 Units under construction expected to be available by July 2001.
PJM Evolving Market Structure
The PJM market has several well defined products which overlap directly
with the ICF energy and capacity products. As mentioned, the ICF modeling
methodology is directly applicable to multiple market constructs including
bilateral or highly structured markets. Exhibit 2-8 illustrates the PJM product
layout correspondence to the ICF modeling representation.
Exhibit 2-8
PJM Product Overlap
- --------------------------------------------------------------------------------
PJM Product Market ICF Modeling
- --------------------------------------------------------------------------------
LMP(1) Energy(1)
- --------------------------------------------------------------------------------
Capacity Credit
- -------------------------------- Pure Capacity
Firm Transmission Rights
- --------------------------------------------------------------------------------
1 Actual LMPs have historically reflected capacity value in addition to
energy value, although by definition, it is an energy only product.
Energy - LMP
The market-clearing price in the PJM energy market is based on Locational
Marginal Prices (LMP). The PJM approach represents the most complex, but
economically efficient, means for managing transmission congestion. Over 1,700
nodes exist. LMPs are the marginal cost of supplying the next increment of
electric power demand at a specific location (node) on the electric power
network, taking into account both generation marginal cost and the physical
congestion of the transmission system.
LMPs are:
o Based on actual flow of energy
o Based on the actual system operating conditions when the
transmission system is unconstrained, LMPs are equal at all
locations
- --------------------------------------------------------------------------------
55 [LOGO] ICF CONSULTING
o Under constrained conditions, LMPs vary by location.
Alternative congestion management approaches are used in California, New
York, and New England. California uses a zonal approach and New England conducts
redispatch and spreads these redispatch costs across all market participants.
New York has recently moved to a system very similar to PJM's using a nodal
pricing method based on Locational Based Marginal Prices (LBMP).
Capacity
The PJM Capacity Credit is currently the most active capacity market in
the U.S., and is the only market which trades capacity on a day-ahead basis.
Although the PJM capacity credit is similar to the New England installed
capacity (ICAP) and New York capacity markets, the PJM capacity market is more
active and has had non-zero market clearing prices. The PJM Capacity Credit
Markets operate on a daily or a monthly basis.
o In the daily auction, one load-serving entity (LSE) would offer to
sell a credit for generation capacity for a particular day at a
particular price (Sell Offer). Another LSE would offer to buy the
daily capacity credit (Buy Bid).
o In the monthly market, an LSE would make a Sell Offer for a credit
for generation capacity for a particular month of the following
twelve months at a particular price. Another LSE would make a Buy
Bid for a monthly capacity credit.
After receiving all the Sell Offers and Buy Bids, the PJM-Office of the
Interconnection ranks the Sell Offers from the lowest to the highest, and ranks
the Buy Bids from the highest to the lowest. The market-clearing price is the
price at which the next (or marginal) Sell Offer is equal to or less than the
next (or marginal) Buy Bid. All sellers of generation capacity credits in this
auction receive the market-clearing price. An LSE that does not meet its
obligation under the Reliability Agreement must pay a fixed capacity deficiency
charge.
After June 1, 1999, when the Reliability Assurance Agreement commenced,
the basis for capacity obligation changed. Prior to June, the installed capacity
obligations of each utility in the PJM Interconnection Agreement were in place.
After June 1, the capacity obligation changed to an unforced capacity basis.
Unforced Capacity is defined as installed capacity rated at summer conditions
that is not on average experiencing a forced outage or forced derating,
calculated for each Capacity Resource on a rolling 12-month average (which shall
be updated each month for the 12 months ending two months prior to the billing
month) without regard to the ownership of or the contractual rights to the
capacity of the unit.
Transmission
FTRs are credits, associated with specific Points of Injection (POI) and
Points of Withdrawal (POW), that protect the holder against any transmission
congestion charges that may be incurred due to LMP price differences. The holder
is entitled to a stream of revenues or charges based on the hourly energy price
differences. FTRs were designed to complement LMP and to provide PJM market
participants with a method for price certainty when moving energy across the PJM
system. FTRs may be purchased by any PJM transmission customer and may be traded
separately from the transmission service, either bilaterally or through an
auction process.
- --------------------------------------------------------------------------------
56 [LOGO] ICF CONSULTING
FTR auctions are held once a month and each auction consists of an on-peak and
off-peak auction.
- --------------------------------------------------------------------------------
57 [LOGO] ICF CONSULTING
CHAPTER THREE
THE WSCC REGIONAL WHOLESALE MARKETS
- --------------------------------------------------------------------------------
Introduction
Although PPL has historically had operations centralized in PJM, they have
recently expanded operations into western U.S. power marketplace regions. PPL
owns generating stations in Montana and Arizona. The western markets offer
significant diversity from eastern areas for several reasons, primarily because
the Western Systems Coordinating Council (WSCC) is not synchronized with either
the Eastern Interconnect or ERCOT, and hence, transmission into these other
interconnects is relatively limited.
Exhibit 3-1
WSCC Regional Division - ICF Defined Transmission Regions
[MAP]
- --------------------------------------------------------------------------------
58 [LOGO] ICF CONSULTING
WSCC is the single largest NERC region in geographic terms. It is a
synchronized, highly interconnected area that includes most of the contiguous
United States west of the Mississippi River, British Columbia and Alberta. This
area contains over 150,000 MW of installed generating capacity. In comparison, a
large single reliability council in the Eastern Interconnect, SERC, peaks at
roughly 137,000 MW.
Although the largest single NERC region, the WSCC is much smaller than the
Eastern Interconnect, the comparable power grid interconnection in the east. The
WSCC is also distinguished by large amounts of regional hydro resources combined
with significant subregional load diversity (winter peaks in the Northern WSCC
regions and summer peaks in the Southern WSCC areas). The transmission grid
within the WSCC was largely designed to take advantage of the availability of
low cost hydroelectric power in the northwest, and the load diversity across the
WSCC. For example, to take advantage of both these characteristics, very large
long distance lines were built to distribute available power from the northwest,
particularly to California. Relative to the Eastern Interconnect, energy trading
within WSCC is extensive, and power flows between sub-regions are enormous. The
transmission capabilities and load diversity are captured in ICF modeling.
Market Structure - Participants
Exhibit 3-2
WSCC Historical Market Participants
[MAP]
The Arizona/New Mexico marketplace includes all of Arizona, most of New Mexico,
and a small portion of western Texas. The market is largely comprised of public
entities and also includes approximately three dozen cooperative and municipal
systems. The major investor
- --------------------------------------------------------------------------------
59 [LOGO] ICF CONSULTING
owned utilities include Arizona Public Service, Tucson Electric, Public Service
of New Mexico, El Paso Electric, Texas-New Mexico Power, and Citizen's
Utilities. Public Service of New Mexico recently announced plans to acquire
Western Resources. The acquisition would give them stronger links to the eastern
SPP markets. The individual entities in the marketplace do not coordinate
activities as they would in a tightly dispatched power pool such as occurs in
California. Despite this loose market structure there is an active energy market
in the region. Additional liquidity results from the strong California
interconnects; several larger coal and nuclear units are owned by California
utilities and there are extensive transfers into California.
The Montana region covers most of the state of Montana with the exception
of the far northwestern corner which is considered part of the Pacific
Northwest. The single largest player in this market has been Montana Power
Company although Bonneville Power Administration (BPA) also supports some load
in the region.
Directly to the west of the Montana region is the Pacific Northwest.
Within PacNW, BPA, Portland General Electric and Pacific Gas and Electric are
the largest players, although several other entities such as Puget Sound Power
and Light, Washington Water Power Company, and Idaho Power Company are active
players supporting regional load. PacNW is dominated by hydroelectric resources.
It is well interconnected with British Columbia to the North and California to
the South. The strong interconnections were designed to allow California to take
advantage of the availability of low east hydro resources in the northern areas,
and to allow both areas to benefit from both seasonal and diurnal load
diversity.
Transmission Within WSCC
Exhibit 3-3 summarizes the average total transfer capability among the
major power markets in the WSCC.
- --------------------------------------------------------------------------------
60 [LOGO] ICF CONSULTING
Exhibit 3-3
WSCC Total Transfer Capability (GW)
[MAP]
Source: 1998 WSCC Path Rating Catalog; Power Pool of Alberta
As mentioned earlier, WSCC has very strong interconnections across
regions. The capacity between regions is highly dynamic and varies greatly on an
hourly, daily, and seasonal basis. Transmission activity reflects existing base
transfer levels based primarily on firm contracts, unit performance, system load
levels, and transmission grid performance.
The primary interconnections between Arizona/New Mexico and neighboring
systems consist of:
o Four 500 kV interconnections with Southern California;
o Two 345 kV interconnections with The Rocky Mountain Power Authority;
o One 345 kW interconnection with the Southwest Power Pool.
Transfers are constrained between Arizona and California during high
demand periods with insufficient transfer capability to meet demand levels in
California. Over time, as demand increases in Arizona/New Mexico such that less
generation is available for export, the constraint should become less
significant in determining regional pricing.
Montana Region has connections with 4 regions:
o Its largest connection is with the Pacific Northwest with about
2,200 MW to PACNW through BPA. Transmission flows in the peak
periods are generally through PACNW to California although flows may
be reversed in non-peak hours.
o Its smallest tie is directly to the Rocky Mountain Area.
o Its ties to NWPP-East are through a very thin transmission system in
Wyoming.
- --------------------------------------------------------------------------------
61 [LOGO] ICF CONSULTING
o It has limited connection to the Eastern Interconnect through MAPP.
PacNW is among the regions with the greatest interconnect
capability. The primary interconnections between PacNW and
neighboring regions include:
- An AC interconnection to Montana through BPA allowing for
roughly 1.2 GW of exports and 2.2 GW of imports
- A major DC interconnection to Southern California, allowing
for approximately 3.1 GW of plan in either direction
- A large connection to British Columbia to the North. In
general, this allows for even greater available megawatts to
move south
- A large 5 GW export capability to Northern California
- A significant interconnection to NWPP-East with approximately
2.4 GW in import capability, allowing for flows into PacNW and
to California with a 1.2 GW export capability which supports
reversed flows in the off-peak.
Intra-Regional Transmission
The utilities within the Arizona/New Mexico system are interconnected via
a high voltage system made up of 500 kV and smaller lines. These are illustrated
in Exhibit 3-4. The internal power flow within the Arizona/New Mexico region is
very significant and includes several important transmission sub-systems.
Relative to the rest of the WSCC, the Arizona/New Mexico region has very high
import and export capabilities. The region can meet approximately 25 percent of
its peak demand through imports and has the capability to export nearly 60
percent of its peak demand. This discrepancy in import/export ability is largely
due to the abundance of export capability to Southern California.
A group of nine southwestern utilities, in coordination with other
interested parties, are forming the Desert Southwest Transmission and
Reliability Operator (Desert Star). Desert Star will be configured into 10
zones, simulating the service areas of the 10 largest utilities in AZ/NM.
Transmission charges will include an access fee component that varies depending
on which zone is being entered, but there is no pancaking of transmission
charges within Desert Star. The largest peak/off peak spread would be 2:1, with
additional charges for losses and transmission congestion.
- --------------------------------------------------------------------------------
62 [LOGO] ICF CONSULTING
Exhibit 3-4
Arizona/New Mexico Intra-Regional Transmission
[MAP]
As seen in Exhibit 3-5, a 500kV support line runs East-West across the
state of Montana. This line allows to the western regions to the low cost coal
units located in the PRB area. This large transmission capability is
supplemented by smaller localized lines. Similarly, in PacNW, an array of 500 kV
and 345 kV lines exist to supplement local and through transmission flows.
- --------------------------------------------------------------------------------
63 [LOGO] ICF CONSULTING
Exhibit 3-5
Montana and PacNW Intra-Regional Transmission
[MAP]
Capacity and Generation Mix
The capacity mix in AZ/NM is diverse. Significant fractions of total
installed capacity comes from coal, nuclear, hydro, combined cycles, turbines,
oil/gas steam units, and pumped storage. Coal, nuclear, and hydro have been the
main components of the capacity and generation mix and are expected to remain as
such. The generation on the margin - i.e., the price setting plants - was
traditionally dominated by conventional oil or gas steam but this has recently
changed to turbines. A further change is expected as these turbines are replaced
by lower cost combined cycle units. Infra-marginal capacity includes hydro and
long-term hydro imports, coal, nuclear, and oil/gas steam.
The baseload low variable cost capacity in AZ/NM is dominated more by
hydro, nuclear, and particularly coal capacity. The Palo Verde nuclear unit
(3,684 MW) in Arizona is the largest in the U.S., and the region also has
several large hydro units, including Glen Canyon and the Hoover units. The
dependence on these units is expected to decrease as combined cycles are built
to replace high cost older plants. AZ/NM does not rely to any large extent on
independent power producers (IPP's).
With the retirement of the existing nuclear facilities and the
construction of new gas-fired facilities, the region is expected to become
increasingly tied to gas. Since 1999, nearly two GW of new gas-fired capacity
has either come on-line or is expected to be operational by the end of 2001. The
ICF forecast also calls for a number of gas-fired units to be added over the
time horizon.
- --------------------------------------------------------------------------------
64 [LOGO] ICF CONSULTING
Generation reflects the utilization of available capacity. Typically,
lower variable-cost resources will have higher utilization, and consequently, a
larger share of the generation mix relative to their share of total capacity.
The nuclear and coal steam generators are low-variable-cost, base-load
resources, and that explains why their share of generation is larger than their
share of capacity. Conversely, combustion turbines are a high-variable-cost
resource and their share of generation is 3 percent in AZ/NM despite comprising
10 percent of installed capacity. The most recent regional generation data
available from NERC is from 1997. Since then, a number of gas-fired units have
been planned or have begun operating, further altering the capacity and
generation mixes towards gas units. As a proxy for more recent historical
values, ICF has estimated the total capacity and generation mixes for 1999.
These values are shown in Exhibit 3-6 and should be considered representative
only.
Exhibit 3-6
Arizona/New Mexico Historical Regional Capacity and Generation Mix - 1999
Capacity Generation
[PIE CHART] [PIE CHART]
Total Capacity = 15,970 MW Total Generation = 74,466 GWh
Sources: Capacity mix from NERC EDS&D 2000; generation derived from EIA Forms
759 and 900. Note, capacity and generation data may not be fully consistent, but
do serve as a proxy for actual regional totals.
- --------------------------------------------------------------------------------
65 [LOGO] ICF CONSULTING
Exhibit 3-7
Montana Regional Capacity and Generation Mix - 1999
Capacity Generation
[PIE CHART] [PIE CHART]
Total Capacity = 3,211 MW Total Generation = 27,610 GWh
Sources: Capacity from ICF proprietary IPM database; generation derived from EIA
Forms 759 and 900. Note, capacity and generation data may not be fully
consistent, but do serve as a proxy for actual regional totals.
Montana is dominated by coal units accounting for roughly 71 percent of
the total capacity in the region. Hydroelectric capacity accounts for most of
the remaining capacity, with roughly 26 percent of the total. Montana has excess
supply over current internal load levels. Given the low cost of the coal and
hydro units, much of the excess is actually operated and dispatched for export
purposes.
Exhibit 3-8
PacNW Regional Capacity and Generation Mix - 1999
Capacity Generation
[PIE CHART] [PIE CHART]
Total Capacity = 39,337 MW Total Generation = 225,699 GWh
PacNW is dominated by hydroelectric resources as seen in Exhibit 3-8. The
low cost hydro resources tend to make PacNW a conduit to other WSCC regions.
- --------------------------------------------------------------------------------
66 [LOGO] ICF CONSULTING
Exhibit 3-9
Hydro Share of Total Generation by Region
[GRAPH]
Source: EIA-759 (1999) and EIA-900 (1999)
To emphasize the importance of hydro in the Northwest, a comparison of
hydro generation is seen in Exhibit 3-9. NWPP is roughly triple that of
California in reliance on hydro resources as measured as a share of total
generation.
Supply and Demand Balance
AZ/NM is a relatively small marketplace compared to other WSCC markets,
particularly neighboring California. With approximately 16 GW of peak demand,
AZ/NM is less than one-third the size of California. Arizona does have very
strong transmission links to California and much of the existing regional
capacity is actually dedicated to serving California internal load. More
recently, the market supply and demand balance has gotten tight and existing
resources have been reserved to serve the Arizona/New Mexico market rather than
the demand in California. As such, high demand periods in the Arizona/New Mexico
markets could actually contribute to higher prices and price spikes in
California. That is, the volatile levels in the Desert Southwest, in part, drive
the pricing in the California markets.
AZ/NM load and energy requirements have been growing at a significantly
higher rate than the U.S. average - on average over 3.5 percent over the last 20
years. Similar to other regions, very little capacity was added during the
1990's. In recent years it has moved closer to being in supply/demand balance
with continued demand growth. As such, high power prices have been apparent in
the market and have triggered the interest of developers resulting in a number
of announced capacity additions.
- --------------------------------------------------------------------------------
67 [LOGO] ICF CONSULTING
Exhibit 3-10
Arizona/New Mexico Long-Term Annual Demand Growth Rates
- --------------------------------------------------------------------------------
Year Peak Demand (%) Energy Demand (%)
- --------------------------------------------------------------------------------
1990 - 2000 3.3 N/A
- --------------------------------------------------------------------------------
1989 - 1999 2.7 2.8
- --------------------------------------------------------------------------------
1988 - 1998 4.0 3.5
- --------------------------------------------------------------------------------
1987 - 1997 3.9 3.8
- --------------------------------------------------------------------------------
1986 - 1996 3.8 4.4
- --------------------------------------------------------------------------------
1985 - 1995 3.8 3.8
- --------------------------------------------------------------------------------
1984 - 1994 4.1 4.5
- --------------------------------------------------------------------------------
1983 - 1993 3.9 4.5
- --------------------------------------------------------------------------------
1982 - 1992 4.1 3.3
- --------------------------------------------------------------------------------
Rolling 10-year average from
1979 3.8 3.9
- --------------------------------------------------------------------------------
Source: NERC ES&D.
As noted above, the long-term average growth in AZ/NM has been very strong
at roughly 3.8 percent for peak demand. In comparison, the US average growth
trends have been roughly 2.5 percent.
Exhibit 3-11
Arizona/New Mexico Historical Peak Demand and Energy Growth Rates
- --------------------------------------------------------------------------------
Peak Demand Peak Demand Energy Demand Energy Demand
Year (MW) Growth (%) (GWh) Growth (%)
- --------------------------------------------------------------------------------
2000 17,406(1) 9.1 N/A N/A
- --------------------------------------------------------------------------------
1999 15,961 -3.7 80,538 -2.0
- --------------------------------------------------------------------------------
1998 16,575 6.5 82,202 -1.9
- --------------------------------------------------------------------------------
1997 15,557 3.1 83,758 5.7
- --------------------------------------------------------------------------------
1996 15,087 3.6 79,247 7.5
- --------------------------------------------------------------------------------
1995 14,566 4.2 73,746 2.0
- --------------------------------------------------------------------------------
1994 13,985 7.1 72,299 5.8
- --------------------------------------------------------------------------------
1993 13,057 0.8 68,332 3.1
- --------------------------------------------------------------------------------
1992 12,956 9.0 66,296 3.6
- --------------------------------------------------------------------------------
1991 11,892 -5.3 63,999 0.4
- --------------------------------------------------------------------------------
1990 12,553 3.1 63,743 4.2
- --------------------------------------------------------------------------------
1989 12,176 8.7 61,192 4.8
- --------------------------------------------------------------------------------
1988 11,205 6.0 58,393 1.6
- --------------------------------------------------------------------------------
1987 10,570 2.2 57,454 11.7
- --------------------------------------------------------------------------------
1986 10,347 2.7 51,456 1.6
- --------------------------------------------------------------------------------
1985 10,072 7.3 50,635 8.4
- --------------------------------------------------------------------------------
1984 9,384 5.5 46,695 5.9
- --------------------------------------------------------------------------------
1983 8,899 2.2 44,082 -7.7
- --------------------------------------------------------------------------------
1982 8,707 N/A 47,741 N/A
- --------------------------------------------------------------------------------
1 Calculated from WSCC 2001 Summer Assessment.
Source: NERC ES&D.
Approximately 1.8 GW of capacity is expected to be on-line by the
beginning of 2002. However, high demand growth in the region is expected to
cancel out the effects of the new units. This is compounded by the effect of the
imbalance in the California markets which are not expected to fulfill capacity
requirements in the near-term. Any capacity shortfalls in California
- --------------------------------------------------------------------------------
68 [LOGO] ICF CONSULTING
will likely increase prices in AZ/NM, and thus further increase the
attractiveness of the region to developers.
Exhibit 3-12
NWPP Historical Peak Demand and Energy Growth
- --------------------------------------------------------------------------------
Year Peak Demand (MW) Energy Demand (GWh)
- --------------------------------------------------------------------------------
1999 38,258 237,725
- --------------------------------------------------------------------------------
1998 42,606 232,807
- --------------------------------------------------------------------------------
1997 38,542 224,884
- --------------------------------------------------------------------------------
1996 39,147 230,508
- --------------------------------------------------------------------------------
1995 41,230 220,068
- --------------------------------------------------------------------------------
1994 37,145 219,573
- --------------------------------------------------------------------------------
1993 37,255 217,699
- --------------------------------------------------------------------------------
1992 38,904 215,782
- --------------------------------------------------------------------------------
1991 34,808 214,926
- --------------------------------------------------------------------------------
1990 40,935 212,717
- --------------------------------------------------------------------------------
1989 33,927 206,312
- --------------------------------------------------------------------------------
1988 38,945 198,092
- --------------------------------------------------------------------------------
Historical Annual Average Growth Rate (%)
- --------------------------------------------------------------------------------
10 year rolling averages
1983 - 1999 1.5 1.9
- --------------------------------------------------------------------------------
Source: NERC ES&D
Note: Peak demand figures are winter demand.
Winter peak demand growth rates in NWPP have been stable over the last 10
years, slightly stronger growth has occurred in the more recent past,
particularly through 1998. Growth was stagnant in 1999.
Exhibit 3-13
Historical Demand Levels, Montana and PacNW versus NWPP
- -----------------------------------------------------------------------------------
Montana(1) PacNW Northwest Power Pool(2)
----------------------------------------------------------------------
Year Winter Peak Winter Peak Winter Peak
Demand Energy Demand Energy Demand Energy
(MW) (GWh) (MW) (GWh) (MW) (GWh)
- -----------------------------------------------------------------------------------
1994 1,937 11,610 29,591 174,549 5,657 66,414
- -----------------------------------------------------------------------------------
1998 2,032 11,512 34,055 185,739 6,519 35,556
- -----------------------------------------------------------------------------------
Average
Annual
Growth (%) 1.2 -0.2 3.2 1.4 3.2 1.4
- -----------------------------------------------------------------------------------
1 Derived from FERC 714 filings for Montana Power Company (MPC) and
Bonneville Power (BPA) adjusted for Montana load based on discussions with
BPA staff, and EIA end-user sales reports.
2 NERC ES&D.
Recent load growth in Montana has not been as strong as evidenced in other
parts of WSCC. The larger Northwest Power Pool has grown at roughly 3.2 percent
in peak demand while Montana has experienced much lower levels. Given the
relatively low load growth, Montana is not expected to experience severe
shortages of capacity.
Montana is dominated by highly reliable baseload coal units. However, the
variability associated with hydro generation limits the ability to plan to
heavily rely on these units in peak
- --------------------------------------------------------------------------------
69 [LOGO] ICF CONSULTING
periods. Also, Montana is highly impacted by events in the larger WSCC to the
extent that export capability can be utilized for external regional demand for
megawatts.
Growth in the Pacific Northwest area of NWPP has been much stronger.
Despite the high growth and heavy reliance of neighboring regions on PacNW
resources, there has been extremely limited new construction activity in PacNW.
As such, with continued strong demand growth, particularly at the summer peak
when export demand is high, shortages could result.
Near-Term Hydro Conditions
As indicated, the Northwestern U.S. is largely reliant on hydro resources
for power generation. As the supply/demand balance tightens, small changes in
hydro conditions could have severe consequences to the grid. Current
hydrological conditions indicate that the Northwest will face challenges over
this year.
Exhibit 3-14
Comparison of 2000 and 2001 Winter Conditions
- --------------------------------------------------------------------------------------------------
Streamflow Conditions (in
percent of 60 year average) November December January February March
- --------------------------------------------------------------------------------------------------
2000-2001 Natural
Streamflow at the Dalles 69.1% 60.1% 57.5% 50.8% 50.0%(1)
- --------------------------------------------------------------------------------------------------
Critical Year Natural
Streamflow at the Dalles 57.0% 54.2% 42.0% 48.4% 54.8%
- --------------------------------------------------------------------------------------------------
1995-2000 Average Natural
Streamflow at the Dalles 112.8% 125.2% 135.8% 160.7% 149.0%
- --------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
FEDERAL HYDRO
GENERATION November December January February March
- -------------------------------------------------------------------------------------------------------
2001-2001 Federal Hydro
Generation 7,316 7,971 7,268 6,500 - 7,500(2)
- -------------------------------------------------------------------------------------------------------
1995-2000 Average Federal
Hydro Generation 8,066 10,620 11,629 11,706 11,246
- -------------------------------------------------------------------------------------------------------
1 Observed through the 12th, forecast for the remainder of the month.
2 Includes observed data and forecasted.
Source: Bonneville Power Administration.
Exhibit 4-14 indicates that natural streamflows in January 2001 were about
60 percent of average. By comparison, from 1995-2000 the region's water supply
ranged from normal to well above normal. Hydro generation in February and March
2001 was expected to be 35 to 45 percent lower than the 1995-2000 average hydro
generation (6,500-7,500 compared to the average of 11,476).
Low streamflow and snowpack conditions have reduced the amount of hydro
power generation available in the region. As of March 1, the weighted Columbia
Basin snowpack was 53 percent. The historic low year of 1977 had a slightly
lower March 1 overall snowpack.
There is a strong possibility that the Northwest region will suspend its
fish operations by this summer. According to the Bonneville Power Administration
(BPA), 53 MAF (million acre feet) is the threshold at which BPA cannot
simultaneously maintain financial solvency, meet its
- --------------------------------------------------------------------------------
70 [LOGO] ICF CONSULTING
firm load, maintain any spill for fish and keep reservoirs from drafting below
summer limits. The March mid month forecast at the Dalles is close to this
threshold, and is about 58 MAF.
According to an analysis by the Northwest Power Planning Council, drafting
reservoirs deeper than the Biological Opinion(9) limits has no immediate effect
on the fish. However the current drafting will reduce Columbia River flows by 3
percent in the spring and 15 percent in the summer. Further, releasing more
water out of Grand Coulee Dam will not have any immediate effect on endangered
fish. Although it could reduce the possibility that reservoirs will be able to
refill to provide targeted river flows for fish during the spring and summer.
In part, severe conditions are alleviated by an agreement between BPA and
California that calls for a two-for-one power exchange agreement wherein
California returns double the megawatts that BPA exports. Thus, the Northwest
gets a bonus which helps keep reservoir levels high. The additional return
represents power that the region does not have to generate at dams or buy on the
market. Through March, California had returned 170 percent of the power,
resulting in the Grand Coulee reservoir being 1.25 feet higher than it would
have been in the absence of the exchange. This is equivalent of the power a
nuclear plant would generate in a week. As of March 7, there is a negative
balance (-749 MW) on the power exchange with the California Independent System
Operator, implying that ISO sent BPA more than required as per the 2 for 1
exchange agreement.
Exhibit 3-15
The Water Situation
[GRAPH]
- ----------
9 The 2000 Biological Opinion on Hydropower Operations is a document issued
by the National Marine Fisheries Service and sets limits on reservoir
drawdowns during winter months in order to have water available for
release in the spring and summer to help fish migrate to the ocean.
- --------------------------------------------------------------------------------
71 [LOGO] ICF CONSULTING ICF CONSULTING
With 2001 shaping up as the second or third driest of the last 73 years,
the Northwest will have far less hydropower than normal (about 60% of normal)
this spring and summer. In order to keep the lights on in the Northwest,
reservoirs behind hydroelectric storage reservoirs in the Columbia River Basin
have been drafted deeper than limits established to protect endangered species
of salmon and steelhead.
Because of the poor hydro conditions anticipated in 2001, the Northwest is
facing the challenge of striking a balance between:
o Providing reliability of power supply,
o Maintaining the targets for reservoir levels, and
o Establishing flows and spill to further the recovery of endangered
species of salmon and other fish stocks.
- --------------------------------------------------------------------------------
72 [LOGO] ICF CONSULTING
CHAPTER FOUR
THE NEPOOL REGIONAL WHOLESALE MARKET
- --------------------------------------------------------------------------------
Introduction
PPL's purchase of the Bangor Hydro assets in 1998 and their subsequent
investment activity makes NEPOOL a focus region of this analysis. This chapter
is designed to give the reader an overview of NEPOOL with emphasis on the
transmission, generation, and market structures that exist today.
NEPOOL has some key structural similarities with PJM owing to its similar
history as a tight multi-utility power pool. For example, both have utility
industry run power exchanges, hourly pool prices, a high enforceable reserve
margin with a separate capacity product, and a single uplift charge regardless
of generator location. However, NEPOOL is smaller, more isolated vis~a~vis other
U.S. areas and more reliant on oil and natural gas. Lastly, NEPOOL has been the
site of more firm new power plant construction as a percent of its peak than any
region examined in this study.
Market Structure - Participants
The New England Power Pool (NEPOOL) had been operated effectively as a
tight pool under the terms of the September 1, 1971, pooling agreement. There
are currently more than 130 NEPOOL participants, including several major
investor-owned utilities, smaller cooperative and municipal systems, power
marketers load aggregators, generation owners, and transmission and distribution
companies.(10)
The major investor-owned utilities are within the six states of
Connecticut, Massachusetts, Rhode Island, New Hampshire, Vermont, and Maine and
they historically included Boston Edison, Central Maine Power, Commonwealth
Electric, Eastern Utilities Association, Maine Electric, New England Electric,
Northeast Utilities, and United Illuminating. Public entities in NEPOOL include
cooperative and municipal systems, either as individual members or represented
collectively by organizations such as the Vermont Group. Exhibit 3-1 graphically
depicts the service areas for major participants in NEPOOLPursuant to Federal
Energy policy Act (EPAct) of 1992, and the ensuing 1996 FERC orders 888 and 889,
which sought to promote greater competition within the electricity industry,
NEPOOL members established ISO-New England, Inc., on July 1, 1997, as a
not-for-profit corporation. ISO-New England was charged with the day-to-day
direction, operation and management of bulk power transmission and generation
facilities in New England. Specifically, their change included unit scheduling
and dispatch, transmission tariff administration, and net interchange settlement
responsibilities.
- ----------
10 Draft rules require members to meet minimum credit worthiness levels. This
can be met either via having an investment grade rating or an irrevocable
and unconditional line of credit. The amount for the line of credit varies
but can reach as high as three and one-half months of expected total
NEPOOL monthly charges. This is for participants with $50,000 per month of
expected charges. NEPOOL can impose changes on what participants estimate
to be their own expected monthly charges.
- --------------------------------------------------------------------------------
73 [LOGO] ICF CONSULTING
Exhibit 4-1
Major Historical Participants in NEPOOL
[MAP]
Transmission Within NEPOOL
The NEPOOL marketplace is part of the Northeast Power Coordinating Council
(NPCC) which is in the northeastern part of the Eastern Interconnected System.
The utilities within the NEPOOL has historically system are interconnected via a
high voltage system made up of 345 kV and smaller lines. These are illustrated
in Exhibit 4-2. The predominant power flow within NEPOOL has historically run
north to south with large quantities of hydro purchases from Hydro Quebec
flowing into Vermont and Massachusetts where a HVDC interconnection with Canada
terminates. Even prior to the ISO-New England NEPOOL had been operated
effectively as a tight pool, resulting in significant economy energy flows
between utilities. Central dispatch supplements bilateral transactions, which
are the majority of economy energy transactions.
- --------------------------------------------------------------------------------
74 [LOGO] ICF CONSULTING
Exhibit 4-2
NEPOOL Intra-Regional Transmission
[MAP]
The NEPOOL market can be divided into four sub-regions: (i) Maine, (ii)
Vermont/New Hampshire, (iii) Massachusetts/Rhode Island, and (iv) Connecticut.
The sub-regions can be said to be a "weak-form" of sub-dividing the NEPOOL
market because with the exception of relatively few number of hours, the
transmission of energy within NEPOOL is not expected to be physically
constrained. The sub-regions have a good network interconnection as shown in
Exhibit 4-2. For example, there is over 1,000 MW of line capacity between Maine
and Vermont/New Hampshire and close to 3,000 MW from Connecticut to
Massachusetts/Rhode Island. All four sub-regions have sufficient transmission
capability to prevent internal price differences. NEPOOL's current tariff covers
all New England. Further, internal ICF modeling results show it to be unlikely
that significant price differences will exist within NEPOOL.
Transmission With Neighboring Regions
Electrically, NEPOOL is relatively isolated from the rest of the NPCC, and
is especially isolated from the rest of the U.S. Eastern Interconnect. While it
is bordered by The New York Power Pool (NYPP), Hydro Quebec and New Brunswick
Hydro, NEPOOL's synchronous electrical connections with these regions are
relatively small (3,000 MW or about 14 percent of peak demand; in the Eastern
Interconnect, average cross-regional AC ties are closer to 20 percent of peak
demand). NEPOOL's DC interconnection with Hydro Quebec adds another 8 percent.
However, in addition to problems commonly associated with AC/DC connections,
Hydro Quebec is far from deregulated, and transactions are focused on long-term
contracts. Furthermore, only about half of the Canadian import capability is
expected to be available in the winter.
- --------------------------------------------------------------------------------
75 [LOGO] ICF CONSULTING
Exhibit 4-3
Eastern Interconnect Total Transfer Capability (GW)
[MAP]
Exhibit 4-3 summarizes the average total transfer capability among the
major power markets in the Eastern Interconnect.
The primary interconnections between NEPOOL and neighboring systems
consist of:
o two high voltage DC connections with Hydro Quebec (Highgate and
Phase II)(11);
o one 345 kV interconnections with New Brunswick;
o two 345 kV interconnections with the New York Power Pool (NYPP).
Total transfer capacity between regions is dynamic and it varies
significantly on an hourly, daily or seasonal basis depending on many factors.
Some of the factors include base transfer levels (primarily associated with firm
power contracts), reactive power compensation, voltage and frequency regulation,
reserved transfer capacity for contingency. Estimated transfers and incremental
transfers above base transfers are:
o Quebec: base import of 1.4 to 1.8 GW with incremental import
capability of 0.3 and 0.6 GW. This fairly large range is due to a
joint transmission constraint on transfers from Quebec to NYPP and
NEPOOL;
o New Brunswick: total import capability of 0.7 GW;
o NYPP: approximately 1.5 GW of transfer capability from NYPP.
Total transfer capability from NEPOOL to other U.S. markets is low; there
is only about 2 GW of transfer capability to downstate New York. This link is
such that NEPOOL and New York both compete for low cost coal power, further
limiting the availability of low-cost coal
- ----------
11 Note, Hydro Quebec is not synchronized with NEPOOL or the Eastern
Interconnect, which is a main reason for the use of a DC rather than an AC
line.
- --------------------------------------------------------------------------------
76 [LOGO] ICF CONSULTING
power from western New York and the rest of the U.S. to NEPOOL. There are,
however, significant ties to Canada.
Capacity and Generation Mix
The capacity mix in NEPOOL is very diverse. Significant fractions of total
installed capacity comes from coal, nuclear, hydro, combined cycles, turbines,
oil/gas steam units, pumped storage units and non-utility generation units
(NUGs). However, conventional utility oil and gas steam capacity has been the
largest component of the capacity mix in NEPOOL and will likely remain as such
for at least a few years.(12) The generation on the margin - i.e., the price
setting plants - is dominated by conventional oil or gas steam but this trend
will change as oil and gas steam generation will be replaced by new and
efficient combined cycle generation. Infra-marginal capacity includes hydro and
long-term hydro imports, coal, nuclear, and some cogeneration.
The baseload capacity in NEPOOL is dominated more by hydro and nuclear
capacity. Hydro capacity is comprised of a combination of local resources as
well as imported resources from Quebec. The dependence on baseload nuclear units
is decreasing due to the recent retirements of Maine Yankee, Connecticut Yankee,
Millstone 1 and Yankee Rowe.
There is very little coal capacity in NEPOOL relative to the rest of the
U.S. This is, in part, explained by the lack of indigenous coal resources and
distance to U.S. coal fields.
NEPOOL also relies extensively on Independent Power Producers(13) (IPP's).
In 1998, IPP's accounted for 20 percent of generation although they account for
12 percent of capacity. Most of these plants use natural gas.
With the retirement of the existing nuclear facilities, the construction
of new gas-fired units, and the addition of new gas pipelines like the Sable
Island project the future of NEPOOL is expected to be increasingly tied to gas
and is expected to continue adding base-load gas-fired capacity (combined cycles
and cogeneration facilities). Construction of over 6000 MW of combined cycles
and cogeneration units is already completed or underway in the region and these
plants are expected to come on-line by 2002(14).
Generation reflects the utilization of available capacity. Typically,
lower variable-cost resources will have higher utilization, and consequently, a
larger share of the generation mix relative to their share of total capacity.
The nuclear and coal steam generators are low-variable-cost, base-load
resources, and that explains why their share of generation is larger than their
- ----------
12 With the exception of Florida, NEPOOL is one of the most dependent on
conventional steam units burning both oil and gas in the US regional
marketplaces.
13 IPP's accounted for 11% of energy requirements in 1995. A favorable
environment for QF development resulted in signed contracts to supply several
thousand MW of QF/IPP capacity in NEPOOL About 2700MW of QF capacity is on-line.
Because a large portion of these units are non dispatchable, they tend to
operate near the bottom of the dispatch stack (variable cost of must run units
being zero thus only marginally affecting energy prices.
14 There have been announced new hydroelectric plants builds in Canada primarily
intended to serve the wholesale power markets in New England and New York. These
planned builds are not expected to come on line soon because the investment cost
of hydro facilities and their associated transmission lines would be prohibitive
compared to natural gas delivered power.
- --------------------------------------------------------------------------------
77 [LOGO] ICF CONSULTING
share of capacity. Conversely, combustion turbines are a high-variable-cost
resource and their share of generation is less than 0.3 percent in NEPOOL
despite comprising 6 percent of installed capacity. The most recent regional
generation data available from NERC is from 1997. Since then, almost 3,000 MW of
nuclear capacity has retired and 3,200 MW of new gas units have come on line. As
a proxy for a more recent historical value, ICF has estimated the total
generation and capacity mixes for 1999. These values are shown in Exhibit 4-4
and should be considered representative only.
Exhibit 4-4
Historical Regional Capacity and Generation Mix - 1999
Capacity Generation
[PIE CHART] [PIE CHART]
Oil/Gas Steam 33% Oil/Gas Steam 30%
Turbine 8% Hydro 4%
Goal 11% Geothermal 0%
Nuke 18% Other 2%
Hydro 14% CC 18%
Other 5% CT 1%
Combined Cycle 11% Coal 15%
Nuclear 30%
Total Cpacity = 23,970 MW Total Generation = 98,583 GWh
Sources: Capacity from NERC ES&D 2000; generation from EIA FOrms 759 and 900.
Note, given differences in the original sources of information, the capacity and
generation mix data may not correspond precisely and should be considered as
approximate only.
Supply and Demand Balance
New England is a relatively small marketplace compared to other power
reliability markets. With approximately 23 GW of peak demand, NEPOOL is less
than half the size of MAIN, ERCOT and PJM (about 50 GW of peak demand each) and
a fourth, the size of ECAR (100 GW of peak demand). New England is a bimodal
peaking system, with demand peaking in both the summer and the winter, although
the summer peak is expected to be higher than the winter peak. In contrast,
nearly all of the remainder of the United States is summer peaking.
Electricity load and generation requirements have been growing
significantly through most of the U.S., with the ten-year rolling average being
about 2.7 percent for energy requirements, and 2.7 percent for peak. However,
generation capacity additions in the US had generally been at a much lower rate
than peak load growth. This was in part attributable to:
o Historical excess capacity that persisted in many regions of the
country after the over-building of large nuclear and coal power
plants in the late 70s and early 80s;
o The effect of the transition from regulation to deregulation.
- --------------------------------------------------------------------------------
78 [LOGO] ICF CONSULTING
NEPOOL load and energy requirements have been growing at a lower rate
relative to the U.S. average - on average between 1.8 and 1.5 percent,
respectively over the last ten to twenty years. Similar to other regions, very
little capacity had been added since in the 1990s. Thus, even with low load
growth, NEPOOL by 1998-1999 needed more capacity. NEPOOL had not experienced a
true shortage situation in 1998, i.e., the period when other when other Eastern
interconnect regions first did, it was very close to being in demand and supply
balance. By 1999 and 2000, the markets experienced severe price spikes.
NEPOOL was quick to deregulate and along with ERCOT quickly became
attractive to developers. High energy prices and arbitrage opportunities against
high heat-rate oil and gas steam units resulted in a large number of announced
capacity additions. More than 20 GW of new capacity has been announced. With
approximately 6,500 megawatts that will likely be online by 2002, NEPOOL may
experience a slight level of excess capacity relative to internal load
requirements. However, this excess can be absorbed by neighboring New York which
is also not far from supply and demand balance, and is experiencing much less
new generation interest and construction.
This balance could be temporarily lost even without more construction if
Hydro Quebec enters the market supplying the market a firm product. We do not
assume herein that Hydro Quebec is willing to offer supply in which non-Quebec
customers have first call on its megawatts. This reflects in part political
factors. However, even if this is not true, this assumption may not be fully in
appropriate. As a large player, Hydro Quebec may be able to modulate its bids
and keep itself from tipping the market into excess. Exhibits 4-5 and 4-6 show
the historical peak demand and energy growth rates.
- --------------------------------------------------------------------------------
79 [LOGO] ICF CONSULTING
Exhibit 4-5
NEPOOL Historical Peak Demand and Energy Growth Rates
- --------------------------------------------------------------------------------
Year Peak Demand Peak Demand Energy Demand Energy Demand
(MW) Growth (%) (GWh) Growth (%)
- --------------------------------------------------------------------------------
2000 21,919(1) -2.8 125,146(2) 2.7
- --------------------------------------------------------------------------------
1999 22,544 5.3 121,873 4.3
- --------------------------------------------------------------------------------
1998 21,406 4.1 116,888 1.1
- --------------------------------------------------------------------------------
1997 20,569 5.4 115,582 0.8
- --------------------------------------------------------------------------------
1996 19,507 -4.8 114,655 1.6
- --------------------------------------------------------------------------------
1995 20,499 -0.1 112,844 0.6
- --------------------------------------------------------------------------------
1994 20,519 4.8 112,187 1.5
- --------------------------------------------------------------------------------
1993 19,570 4.6 110,538 1.6
- --------------------------------------------------------------------------------
1992 18,707 -5.3 108,825 0.1
- --------------------------------------------------------------------------------
1991 19,755 3.3 108,682 -1.0
- --------------------------------------------------------------------------------
1990 19,131 -2.6 109,762 -2.0
- --------------------------------------------------------------------------------
1989 19,641 0.6 111,982 1.7
- --------------------------------------------------------------------------------
1988 19,525 8.0 110,084 5.2
- --------------------------------------------------------------------------------
1987 18,081 12.9 104,620 5.3
- --------------------------------------------------------------------------------
1986 16,020 -6.1 99,363 4.9
- --------------------------------------------------------------------------------
1985 17,058 4.8 94,750 1.8
- --------------------------------------------------------------------------------
1984 16,274 3.1 93,117 5.0
- --------------------------------------------------------------------------------
1983 15,785 2.5 88,727 5.3
- --------------------------------------------------------------------------------
1982 15,400 N/A 84,230 N/A
- --------------------------------------------------------------------------------
1 NEPOOL ISO reported June 2000 Peak.
2 NEPOOL ISO April 2001 Short-Run NEA Energy for Load Forecast.
Source: NERC ES&D, unless otherwise noted.
Exhibit 4-6
NEPOOL Long-Term Annual Demand Growth Rates
- --------------------------------------------------------------------------------
Year Peak Demand(%) Energy Demand(%)
- --------------------------------------------------------------------------------
1990 - 2000 1.4 1.3
- --------------------------------------------------------------------------------
1989 - 1999 1.4 0.9
- --------------------------------------------------------------------------------
1988 - 1998 0.9 0.6
- --------------------------------------------------------------------------------
1987 - 1997 1.3 1.0
- --------------------------------------------------------------------------------
1986 - 1996 2.0 1.4
- --------------------------------------------------------------------------------
1985 - 1995 1.9 1.8
- --------------------------------------------------------------------------------
1984 - 1994 2.3 1.9
- --------------------------------------------------------------------------------
1983 - 1993 2.2 2.2
- --------------------------------------------------------------------------------
1982 - 1992 2.0 2.6
- --------------------------------------------------------------------------------
Rolling 10-year average from
1979 2.1 1.9
- --------------------------------------------------------------------------------
Source: NERC ES&D.
The long-term growth trends within NEPOOL have been below the U.S. average
levels. However, since 1997, peak demand growth has been relatively strong while
energy growth has been generally at lower levels.
- --------------------------------------------------------------------------------
80 [LOGO] ICF CONSULTING
Exhibit 4-7
Forecast NEPOOL Supply and Demand Balance, 2001
- --------------------------------------------------------------------------------
Demand for Gigawatts Supply of Gigawatts
- --------------------------------------------------------------------------------
Peak Demand(1) 23.5 Existing Capacity(3) 27
- --------------------------------------------------------------------------------
Interruptible/
Controllable Load(1) 0.0 Net Firm Imports(4) 0
- --------------------------------------------------------------------------------
Net Peak Demand1 23.5 Inoperable Capacity(1) 0
- --------------------------------------------------------------------------------
Reserve Margin 18%(2) 4.2 New Builds(5) 0.9
- --------------------------------------------------------------------------------
Total Need 27.8 Total Supply 27.9
- --------------------------------------------------------------------------------
Expected Reserve Margin(6) (%): 18.7
- --------------------------------------------------------------------------------
Surplus Gigawatts: 0.1
- --------------------------------------------------------------------------------
1 Source: NERC ES&D 2000, ICF assumed growth rate.
2 ICF Assumption; note that ICF forecasts reserve margins to fall to 15% by
2010.
3 Includes all units on line by summer 2000.
4 ICF Base Case modeling result.
5 Includes units under construction and scheduled to begin operation before
July 2001.
6 Total Supply divided by Net Peak Demand minus 1.
Given the construction of new units in the marketplace, NEPOOL is expected
to be in an equilibrium level in 2001.
NEPOOL Market Structure
New trading markets have been developed in NEPOOL since the formation of
the ISO covering "regular" energy, a capacity product and ancillary services.
Some are distinctive relative to the rest of the U.S. though less so vis~a~vis
New York and PJM. This notably includes the ICAP requirement which was formerly
a PX traded item. The NEPOOL product markets are outlined below and historical
data is presented in the Historical Prices section of this document.
o The energy market is a residual market. Only the difference between
a participant's energy resources and its energy obligations is
traded. These resources and obligations include amounts covered by
bilateral contracts.
o The installed capability requirement is a residual requirement that
is emblematic of the unusual market structure in NEPOOL (and in this
case PJM) relative to the rest of the U.S. In particular, there is a
separate, though now completely bilateral capacity market based on
an enforceable and relatively high reserve margin. The difference
between a participant's installed capability resources and its
installed capability obligation (load plus installed operating
reserve) used to be traded through the ISO. Trading in this market
occurred monthly. Bids were submitted in $/MW-month on the last day
before the month begins. A clearing price is calculated based on the
bids of those participants with excess installed capacity.
Participants who are deficient in installed capability pay the
clearing price for each MW-month to those who are in surplus and who
bid a price less than or equal to the clearing price. The ICAP
market was terminated since all transactions were bilateralized, but
the requirement remains.
o The ten minute spinning reserve (TMSR) market is a full requirements
market. All TMSR is bought/sold through the ISO. Designated
resources are paid the energy-clearing price for any MWh provided,
plus lost opportunity cost plus
- --------------------------------------------------------------------------------
81 [LOGO] ICF CONSULTING
production cost changes plus the bid multiplied by times the MW
provided. The total cost of providing TMSR is shared proportionally
by load.
o The ten-minute non-spinning reserve (TMNSR) market is a full
requirements market. All TMNSR is bought/sold through the ISO.
Bidding and settlement are done as in the energy market. Designated
resources are paid the clearing price multiplied by the MW provided
as reserved capacity. The total cost of providing TMNSR is shared
proportionally by load.
o The thirty-minute operating reserve (TMOR) market is a full
requirements market. Designated resources are paid the clearing
price multiplied by the MW provided.
o The automatic generation control (AGC) market is a full requirements
market. Units that can provide AGC at lowest cost based on bids,
lost opportunity costs, and production cost changes are selected.
Generators providing AGC are paid the clearing price for time on AGC
multiplied by the number of regulations plus a payment for AGC
service actually provided plus any lost opportunity cost.
o The operable capability market was a residual market when the market
started. It has since been shut down and the requirement eliminated.
In general, the ICF modeling approach captures the full value of the
non-energy products in the capacity price. The only exception to this is for
units which may receive ancillary revenues such as operating reserve support in
markets where there is a shortage of competing units, e.g., a shortage of quick
start units. This notwithstanding, the ICF firm power price generally represents
the full long-term value that can be earned by individual units. Exhibit 4-8
outlines the overlap between the ICF capacity price forecast and the NEPOOL
products. Note that detailed descriptions of ICF modeling construct is in the
Approach chapter of this document
Exhibit 4-8
NEPOOL Product Overlap
- --------------------------------------------------------------------------------
NEPP Product Market ICF Modeling
- --------------------------------------------------------------------------------
Energy Energy
- --------------------------------------------------------------------------------
Installed Capability (ICAP) - Bilateralized
- -------------------------------------------
Operable Capability (OPCAP) - Discontinued
- -------------------------------------------
Ten Minute Spinning Reserve (TMSR)
- ------------------------------------------- Pure Capacity
Ten Minute Non-Spinning Reserve (TMNSR)
- -------------------------------------------
Thirty Minute Operating Reserve (TMOR)
- -------------------------------------------
Automatic Generation Control (AGC)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
82 [LOGO] ICF CONSULTING
CHAPTER FIVE
MODELING APPROACH AND INPUT ASSUMPTIONS
- --------------------------------------------------------------------------------
Chapter Five has two principal sections. The first section presents the
study modeling approach and methodology and the second presents our input
assumptions.
Modeling
ICF Resources' IPM(TM) is a production cost simulation model focusing on
analyzing wholesale power markets and assessing competitive market prices of
electrical energy, based on an analysis of the fundamentals relating to supply
and demand. The model also projects plant generation levels, new power plant
construction, fuel consumption, and inter-regional transmission flows. The model
determines appropriate production, and therefore production costs and prices,
using a linear programming optimization routine with dynamic effects (i.e., it
looks ahead at future years and simultaneously evaluates decisions over
specified years). All major factors affecting wholesale electricity prices are
covered in this model, including detailed modeling of existing and planned
units, with careful consideration of fuel prices, environmental allowance and
compliance costs, and operating constraints. Based on looking at the
supply/demand balance in the context of the various factors discussed above,
IPM(TM) projects the hourly spot price of electric energy within a larger
wholesale power market. IPM(TM) also projects the annual "pure" capacity price
(i.e., price spike revenues).
The IPM((TM)) addresses a wide range of issues including:
o Projecting of competitive market prices
o Estimating the dispatchability of specific units
o Assessing the revenues and costs of merchant power plants
o Understanding the reasons for long-term dispatch patterns
within power markets
o Assessing the impact of different variables on prices and
dispatch patterns
o Projecting capacity expansion levels and mix
Methodology
The following discussion presents ICF's modeling approach, which assumes a
perfectly competitive market.
Energy and Capacity Pricing Approach
The value of a power plant is assessed within a regional market by
examining the applicable forecast revenues and costs associated with operating
the plant. Power plants provide two primary unbundled products: (i) electrical
energy, and (ii) "pure" capacity. "Pure" capacity increases the reliability of
electrical energy. The sum of the spot price of unbundled electric energy and
the spot price of unbundled capacity is the spot market price of firm
electricity.
- --------------------------------------------------------------------------------
83 [LOGO] ICF CONSULTING
These two products have been of computational necessity and are individually
analyzed; their prices are summarized in this report.
Exhibit 5-1
Firm Power Prices Are the Sum of Energy and Capacity
- An Illustrative Example of a Smooth Transition to Equilibrium
[GRAPH]
There are situations in which electrical energy prices can be observed.
This is because the electrical energy price, as discussed below, also equals the
interruptible power price. In Exhibit 5-2, electrical energy prices are shown to
be increasing across cases from $15 to $28/MWh.
- --------------------------------------------------------------------------------
84 [LOGO] ICF CONSULTING
Exhibit 5-2
Three Examples of Firm Pricing ($/MWh) - Illustrative All-Hours Prices
- --------------------------------------------------------------------------------
Low Prices Medium Prices High Prices
- --------------------------------------------------------------------------------
Electrical Energy
(Interruptible) 15 22 28
- --------------------------------------------------------------------------------
Pure Capacity/Price
Spikes 5 10 20
- --------------------------------------------------------------------------------
Total Firm(1) 20 32 48
- --------------------------------------------------------------------------------
1 Unit contingent firm.
There are also situations in which capacity prices or their equivalent can
be observed. This occurs in marketplaces with separate capacity prices. Markets
without separate capacity markets have price spikes, the sum of which equals the
annual capacity price. This price can also be estimated as a residual between
energy and total firm prices.
Nonetheless, the most commonly observed price is the firm price, i.e., the
sum of the two components. Alternate market structures for pricing are described
in Exhibit 5-3.
Exhibit 5-3
Power Prices - Commercial Topologies versus ICF Approach
- -------------------------------------------------------------------------------------------------
Market Structure/ ICF Approach - How to Map
Commercial Arrangement Energy and Capacity Illustrative Generic Example
- -------------------------------------------------------------------------------------------------
Firm equals hourly energy $500/MWh price at super
Single $/MWh Firm Unit price plus capacity price in peak; energy price contributes
Contingent Price super peak demand hours $50 - $70/MWh; pure capacity
as hourly spikes contributes
the rest
- -------------------------------------------------------------------------------------------------
Firm equals energy plus
Two $/MWh Prices - Firm Unit capacity; interruptible equals $35/MWh Firm
Contingent and Interruptible energy price $30/MWh Interruptible
Difference is pure capacity
- -------------------------------------------------------------------------------------------------
SLD Firm equals energy plus
Single Liquidated Damages capacity times one plus $37/MWh L.D.
$/MWh Firm Price reserve margin $35/MWh Firm Unit
[SLD = E + C (1+RM)] Contingent
$30/MWh Interruptible
- -------------------------------------------------------------------------------------------------
Firm Unit Contingent Supply -
Energy market with very high Market energy exactly equals
and enforceable reserve ICF energy; ICAP price equals $60/kW/yr "ICAP" capacity
margin (e.g., reserve margin is ICF capacity price plus $30/MWh energy
25 percent) price
- -------------------------------------------------------------------------------------------------
Firm Unit Contingent Supply -
Energy market with medium Market price equals energy
high and enforceable reserve price plus some of capacity $32/MWh market energy price
margin (e.g., reserve margin is price in peak hours and $30/kW/yr ICAP capacity
17 percent) price
- -------------------------------------------------------------------------------------------------
Firm Unit Contingent Supply - Equivalent of single $/MWh
Energy market with low and firm unit contingent price Equivalent of single $/MWh
enforceable reserve margin above firm unit contingent price
above
- -------------------------------------------------------------------------------------------------
Note, plants may be able to sell ancillary services. However, in most
situations, in order for plants to make these sales, they require that sales of
"regular" energy and capacity are
- --------------------------------------------------------------------------------
85 [LOGO] ICF CONSULTING
forgone. Thus, in spite of a more varied slate of offerings, plants will still
only be able to earn the level of revenues equal to those made in our assessment
of energy and capacity sales, i.e., they can earn this given amount in one of
several combination of sales (e.g., some ancillary and some energy/capacity) but
cannot earn in total more. For example, the most important ancillary service is
operating reserves. These are units that can supply power on short notice to
make-up for power lost when unexpected unit outages occur, damaged power lines,
or unexpected increases in demand. The opportunity cost of being in reserve is
mainly (in most cases), the cost of not being able to sell "regularly" scheduled
power at prevailing prices. This is discussed further later in this chapter.
Valuation Approach
Valuation in its most mechanical form is a two-step process. First, in
equilibrium, capacity revenues are based on the capacity of the plant and the
annual "pure" capacity price.
Capacity revenues = Capacity (kW) x "Pure" Capacity Price ($/kW/yr)
Second, energy revenues are based on three factors: (i) the capacity of
the plant, (ii) the level of dispatch of the plant, and (iii) the energy price
during hours the plant operates. The level of dispatch, in turn, depends on the
bid. In a competitive market, the bid price reflects the short run variable
costs of the plant, namely the variable component of fuel price, variable O&M
costs of the plant, and any environmental allowance costs.
Energy revenues = Capacity (MW) x Hours of operation (hours) x Realized
Energy Price ($/MWh)
While all available power plants receive similar revenues for capacity (on
a per kW basis), energy revenues will vary across plants.
Note, this approach is appropriate even for markets where no separate
capacity market exists. This ultimately derives from the empirical finding by
ICF that no market in the U.S. in equilibrium will be reliable without a premium
above electrical energy prices. Thus, unless the price is made sufficient in
some manner in the long run, the grid cannot be operated reliably.
In a competitive market, the hourly dispatch of a plant will be based on
economics. That is, if the plant's variable costs are lower than the hourly
market price, the plant will be dispatched. (15 )The margin it will earn will be
the difference between the price in that hour and the variable cost.
Energy Pricing
Competitive wholesale or spot electric energy prices are determined on an
hourly basis by the intersection of supply (the available generating resources)
and demand. In each hour, the prevailing spot price of electric energy will be
approximated by the short run marginal cost of production of the most expensive
unit operating in that hour(16). Thus, the spot electric energy price in the
bulk power market in a given hour is equal to the marginal energy cost in that
hour.
- ----------
15 Some units will be dispatched at minimum turndown levels due to
operational limitations, and hydro plants may be optimized to "peak
shave.".
16 The variable cost may incorporate compensation for lost profits during
turndown hours of operation. When the price exceeds variable costs
including lost profits, it is defined as the hourly pure capacity price.
See "pure" capacity pricing discussion.
- --------------------------------------------------------------------------------
86 [LOGO] ICF CONSULTING
Note that prices are determined hourly because power cannot be readily stored.
These competitive electrical energy prices are also known in the industry as
system lambdas, economy energy, and interruptible power.
Additional detailed dimensions of this problem include:
o Treatment of power imports: Geographically diverse product markets
and prices complicate analysis of the hourly power markets. Exhibit
5-4 shows an external power source, a coal plant located in another
region, that includes an additional wheeling charge. Not only coal,
but any unit could be the source of power.
Exhibit 5-4
Illustrative Supply Curve for Electrical Energy
[GRAPH]
Generation Supply (MW)
Note: Cogeneration units can have a wide range of heat rates. The most efficient
gas cogeneration units are more competitive than gas-fired combined cycles.
During certain seasons, gas-fired cogeneration and combined cycle units can be
more competitive than select coal-fired units.
o Treatment of power exports: For regions supplying power to other
regions, export demand manifests itself as a higher demand and a
shift of the vertical demand curve in that hour to the left.
o Unit operating flexibility: Operational constraints including
minimum run times, start times, and start-up costs need also be
accounted for.
o Environmental compliance issues: The opportunity cost of using
environmental allowances must also be included.
o O&M costs: Proper treatment of non-fuel O&M costs between fixed
annual and per MWh (variable) charges.
- --------------------------------------------------------------------------------
87 [LOGO] ICF CONSULTING
"Pure" Capacity Pricing
Exhibit 5-5 illustrates supply and demand equilibrium for megawatts, the
point at which existing power plant supply is equal to the level of expected
peak demand plus reserve requirements. Our derivation of pure capacity prices
(described in this section) reflects these equilibrium conditions. In other
words, the ICF IPM(TM) power model used here will build to meet reserve margin
if the market is short of capacity and may retire if the region is long.
Exhibit 5-5
Equilibrium in the Capacity Market
[GRAPH]
Equilibrium is defined usually as a condition in which there is sufficient
capacity to meet a planning reserve margin over expected system peak. However,
some regions rely more on operating reserve requirements than on planning
reserve requirements. Either way, significant reserves are needed. That is,
planning reserve requirements are set to ensure that there are enough operating
reserves at peak. Thus, the fact that the model is estimating a separate
capacity price is appropriate even for markets without separate planning reserve
requirements.
Capacity increases the reliability of electrical energy supply.
Consequently, the power price structure must be high enough to ensure that
sufficient "pure" capacity exists (i.e., units which almost never operate are
available and are purely for reserve). To the extent that prices are above
system lambda (i.e., above the competitive electrical energy price or the
marginal variable cost of the last unit dispatched), this premium is the "pure"
capacity price. The "pure" capacity market is not entirely separate from the
energy market, but is linked.
ICF uses a sophisticated computer modeling approach based on a linear
program to forecast capacity prices. Under this approach, all model outputs are
simultaneously determined. However, it is useful to describe this approach using
seven steps.
In Step 1, the potential for excess builds in the near-term is evaluated.
Excess builds have the potential of creating a near-term over supply that could
lower the market price of capacity.
- --------------------------------------------------------------------------------
88 [LOGO] ICF CONSULTING
In Step 2, the annualized costs (capital related and annual fixed non-fuel
O&M) of the least costly type of additional megawatts are estimated. In the
model, these costs are calculated for numerous new plant options (e.g., simple
and combined cycles, and coal plants).
Step 3 is to account for the energy sales profit of new power plants
(i.e., the fact that new plants may not provide strictly "pure" capacity). For
example, if a new power plant can make profit on electrical energy sales, this
diminishes the price premium (i.e., the pure capacity price) required to build
the necessary megawatts for reliability. For example, if a new combustion
turbine can make $10/kW/yr in energy profit and it costs $57/kW/yr to build, the
pure capacity price is $47/kW/yr.
The formula for the Step 3 adjustment is more complicated because all new
potential entrants - e.g., both combined cycles and simple cycles - can profit
from energy sales and both are marginal sources of megawatts. The "pure"
capacity price is driven by the lower capacity price required of the two plants,
as shown in the following, simplified formula:
If (Cx - X) less than or equal to (Cy - Y), then P = Cx - X
If (Cx - X) greater than or equal to (Cy - Y), then P = Cy - Y
Where:
X = Energy sales profits of a new combustion turbine
Y = Energy sales profits of a new combined cycle
Cx = Annual fixed costs of a new combustion turbine
Cy = Annual fixed costs of a new combined cycle
P = "Pure" Capacity Price
Under Step 4, the model makes decisions to import or export firm
megawatts. Thus, the equilibrium in the capacity market is determined by
simultaneously answering three questions: (i) how much reserves are required in
a regional marketplace (with reference to planning reserve requirements and
accounting for demand growth); (ii) how much can be traded; and (iii) what, if
any, retirements or mothballing occur (see Step 5). We highlight trading of firm
capacity rights for megawatts in the capacity pricing discussion because
exporters are at a disadvantage to local generation since transmission charges
are required on firm capacity purchases.
In Step 5, we analyze whether the very last existing units in the dispatch
order should be mothballed or retired if the pure capacity price is not
sufficient to allow them to cover their net fixed, non-fuel, cash-going-forward
costs after energy sales. In addition, the competitive market price for pure
capacity will be less than the required capacity payment for new entrants in
cases of excess capacity unless sufficient retirements or mothballing occur to
bring the market into equilibrium. Our model is distinguished by its ability to
make decisions including retirement and mothballing decisions. It does this by
incorporating expectations about the future through solving all years
simultaneously.
Step 6 addresses the multi-year nature of new power plant investment. The
decision on whether to add new capacity to the system and the type of capacity
to be added depend on the long term potential for recovery of costs associated
with the investment. If the capital costs associated with new power plants are
anticipated to be lower in the future such that the price of "pure" capacity in
those years will also be lower, an additional premium in the early years would
- --------------------------------------------------------------------------------
89 [LOGO] ICF CONSULTING
be warranted and necessary to compensate for lower profits in the out years.
Otherwise, the price will be sufficient for the later entrants to recover costs
and earn a return but not the earlier entrants. This issue exists with some
saliency due to several factors including the possibility that the real costs of
new gas power plants and their heat rates will continue to decrease.
Step 7 addresses the response to interruptible load, market power and
forward trading. The impact of these would be to help create a capacity price
floor. The interruptible load represents a significant force in maintaining
price floors. Customers who may not be willing to pay full price for firm power,
but are willing to pay some value above zero, as such they help set a floor on
capacity prices. This element is captured in our modeling.
The history of interruptible contracts is complicated by the fact that
they have been used to subsidize customers who in fact may best be considered as
firm. In periods of fully available supply, regulators allow so-called
interruptible consumers to pay below market price. In periods of limited supply
availability, the interruptible consumers are then allowed to switch to firm
rates freely. Because of this, consumers are somewhat allowed to misrepresent
whether they are firm or interruptible customers. This contributes to explaining
the large growth in interruptible load. This notwithstanding, we use historical
estimates of interruptible load to be conservative.
Note that market power and forward contracts also contribute to capacity
price floors, although not explicitly captured in our modeling. Market power can
be especially strong at the peak when all megawatts are needed. Forward
contracts hedge against volatility including low capacity prices.
Additionally, the hourly loss of load probability could be evaluated to
calculate the expected unserved energy on an hourly basis and hence, determine
the timing and level of price spikes. This approach is not computationally
feasible.
Regional Assumptions
This section focuses on the key assumptions underlying the analysis. The
major determinants influencing energy and capacity prices in the US power
markets include:
Energy Pricing Capacity Pricing Transmission
Fuel Prices Load Growth Transfer Capability
o Coal Reserve Margin Transmission Pricing
o Gas New Plant Cost and Characteristics
o Oil Financing of New Power Plants
Environmental Compliance
Nuclear Plant Characteristics
Existing Unit Characteristics
o
For all cases analyzed, we model 2001, 2003, 2005, 2010, 2015, 2020, and
2025. We model the Eastern Interconnect as follows:
o PJM (4 regions)
o NEPOOL (1 region)
o ECAR (2 regions)
o MAIN (3 regions)
- --------------------------------------------------------------------------------
90 [LOGO] ICF CONSULTING
o Downstate NY (3 regions)
o Upstate NY (1 region)
o TVA (1 regions)
o MAPP (1 region)
o SPP North (1 region)
o VACAR (4 regions)
o Ontario (1 region)
o Entergy (1 region)
Interactions with other regions are captured exogenously.
In our eastern model we consider four seasons as defined in Exhibit 5-6.
Exhibit 5-6
Seasonal Definition - Eastern Interconnect
--------------------------------------------------------------------------
Season Months Days
--------------------------------------------------------------------------
Summer June, July, & August 92
--------------------------------------------------------------------------
Winter January, February, &
December 90
--------------------------------------------------------------------------
Other March, April, October, &
November 122
--------------------------------------------------------------------------
Shoulder May, September 61
--------------------------------------------------------------------------
The WSCC is modeled as follows:
o Arizona/New Mexico
o Montana
o Pacific Northwest
o Rockies
o NWPP-East
o Northern California
o Southern California
o British Columbia
o Alberta
Other regions are captured exogenously.
In our western model we consider five seasons as defined in Exhibit 5-7.
- --------------------------------------------------------------------------------
91 [LOGO] ICF CONSULTING
Exhibit 5-7
Seasonal Definition - WSCC
- --------------------------------------------------------------------------------
Season Months Days
- --------------------------------------------------------------------------------
Winter January, February, March
December 121
- --------------------------------------------------------------------------------
Hydro Peak April, May, June 91
- --------------------------------------------------------------------------------
Load Peak July, August 62
- --------------------------------------------------------------------------------
September September 30
- --------------------------------------------------------------------------------
Fall October, November 61
- --------------------------------------------------------------------------------
Summary of Assumptions
A summary of key parameters modeled by region is presented in Exhibit 5-8.
Further detail behind these assumptions is contained in the remainder of this
chapter.
Exhibit 5-8
Summary of Key Modeling Assumptions - Base Case
- ----------------------------------------------------------------------------------------------------------------
Region
Parameter -------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ----------------------------------------------------------------------------------------------------------------
2001 Peak Demand (MW)(1,2) 50,410 23,517 21,926 4,610 2,123 17,571 28,091
2001 Net Internal Demand
(MW)(1,2) 50,484 23,517 20,171 4,610 2,091 17,571 27,682
Annual Peak Growth
2001 - 2005(%) 2.4 2.1 2.2 1.7 2.3 3.8 2.3
2006 - 2010(%) 2.1 1.9 2.0 1.5 2.2 3.6 2.2
2011 - 2020(%) 1.9 1.8 1.9 1.3 2.0 3.6 2.0
- ----------------------------------------------------------------------------------------------------------------
2001 Weather-Normalized
Net Energy for Loan
(GWh)(1,2) 264,153 125,333 94,882 19,407 13,065 89,613 192,012
Annual Peak Growth
2001 - 2005(%) 2.2 1.9 2.3 1.6 2.0 3.9 2.0
2006 - 2010(%) 2.1 1.8 2.1 1.5 1.9 3.7 1.9
2011 - 2020(%) 1.9 1.7 1.9 1.3 1.8 3.6 1.8
- ----------------------------------------------------------------------------------------------------------------
Planning Reserve Margin
(%)
2001 19.0 18.0 15.0 18.0 15.0 15.0 15.0
2005 17.8 18.0 15.0 18.0 15.0 15.0 15.0
2010 15.0 17.0 14.0 18.0 15.0 15.0 15.0
2015 15.0 15.0 14.0 14.0 15.0 15.0 15.0
2020 15.0 15.0 13.0 14.0 15.0 15.0 15.0
- ----------------------------------------------------------------------------------------------------------------
Capacity additions that are already completed or have begun construction are
explicitly included in the modeling as "Firm Builds". Beyond this, the model
New Builds optimizes construction of new capacity internally to ensure that reserve
requirements are achieved. The capacity added by the model is determined by
selection the most economical power plant technology option available.
- ----------------------------------------------------------------------------------------------------------------
Firmly Planned Builds (MW)
2000 752 3,536 1,618 0 0 140 0
2001 1,212 934 746 0 0 3,830 1,018
2002+ 3,436 2,435 1,970 270 0 2,300 2,213
TOTAL 7,136 6,905 4,334 270 0 6,270 3,231
- ----------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
92 [LOGO] ICF CONSULTING
Exhibit 5-8 (continued)
Summary of Key Modeling Assumptions - Base Case
- ----------------------------------------------------------------------------------------------------
Region
Parameter -------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ----------------------------------------------------------------------------------------------------
New Unit Combustion Turbines Combined Cycles and LM 6000s
Characteristics -------------------- ------------------- --------
All-In Capital Costs Cogeneration
------------
(1998$/kW)(3) 375 617
2001 375 617 497
2005 357 587 497
2010 339 559 473
2015 323 531 450
2020(4) 428
Levelized 2001- 363 598
2020 482
Fixed O&M
(1998$/kW-yr) 13.5 20.0/21.5 14.8
- ----------------------------------------------------------------------------------------------------
Capital Charge Rate for
New Units(5)
Combustion
Turbines 14.8 15.7 15.8 16.5 15.8 15.5 15.2
Combined Cycle 12.9 13.9 14.0 14.7 14.0 13.7 13.5
LM6000 14.8 15.7 15.8 16.5 15.8 15.5 15.2
- ----------------------------------------------------------------------------------------------------
New Power Plan Combined Cycle Cogeneration Combustion LM6000
Builds -------------- ------------ ---------- ------
Heat Rate Turbine
(Btu/kWh) -------
2001 6,893 6,393 10,858 9,538
2005 6,753 6,253 10,671 9,374
2010 6,583 6,083 10,443 9,173
2015 6,417 5,917 10,219 8,976
2020 6,255 5,755 10,000 8,784
Levelized(4) 2001-
2020 6,680 6,180 10,572 9,287
Variable O&M
(1998$/MWh) 1.1 1.2 2.3 1.1
Minimum Turndown 0 0 0 0
Availability (%) 91.9 91.7 90.7 91.7
- ----------------------------------------------------------------------------------------------------
Existing Power Plant Availability(3) Turndown %
Constraints (%)
Coal Steam 84 - 88 40
Oil/Gas Steam 87 - 91 25
- ----------------------------------------------------------------------------------------------------
Variable O&M
(1998$/MWh) Range(2)
Combined Cycle 0.98 - 7.11
Combustion
Turbine 0.81 - 5.91
Oil/Gas Steam 1.3 - 9.4
Unscrubbed Coal 1.0 - 11.3
Scrubbed Coal 2.1 - 12.3
- ----------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
93 [LOGO] ICF CONSULTING
Exhibit 5-8 (continued)
Summary of Key Modeling Assumptions - Base Case
Treatment
- ----------------------------------------------------------------------------------------------------
Treatment
Parameter -------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ----------------------------------------------------------------------------------------------------
Annual Average
Nuclear Capacity
Factor (%)
2001 86.3 81.7 85.1 N/A N/A 80.5 66.0
2005 86.4 81.7 86.0 80.5 66.0
2010 85.7 81.7 86.3 80.5 66.0
2015 85.0 81.6 85.1 80.5 66.0
2020 86.4 85.0 84.9 80.5 66.0
- ----------------------------------------------------------------------------------------------------
Nuclear Retirements End of operating license
- ----------------------------------------------------------------------------------------------------
Natural Gas
2001 5.33 5.22 5.13 5.52 5.09 5.34 5.00
2005 3.03 2.91 2.84 3.21 2.73 2.80 2.71
2010 3.16 3.03 2.94 3.38 2.63 2.90 2.82
2015 3.35 3.08 2.83 3.63 2.28 2.54 2.48
2020 3.39 3.19 2.74 3.67 2.11 2.38 2.04
Levelized Average
(2001-2020)
3.73 3.59 3.46 3.95 3.23 3.43 3.27
- ----------------------------------------------------------------------------------------------------
Residual1% Oil
2001 3.75 3.76 4.56 4.26 4.72 4.18 4.72
2005 3.27 3.27 3.95 3.77 4.11 3.56 4.11
2010 3.41 3.41 3.95 3.91 4.11 3.57 4.11
2015 3.54 3.54 3.95 4.04 4.11 3.57 4.11
2020 3.54 3.54 3.95 4.04 4.11 3.57 4.11
Levelized Average
(2001-2020)
3.53 3.53 4.17 4.04 4.33 3.78 4.33
- ----------------------------------------------------------------------------------------------------
Distillate Oil
2001 5.23 5.29 5.19 5.93 5.81 5.16 5.81
2005 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2010 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2015 4.52 4.57 4.49 5.21 5.11 4.45 5.11
2020 4.52 4.57 4.49 5.21 5.11 4.45 5.11
Levelized Average
(2001-2020)
4.77 4.83 4.74 5.48 5.37 4.70 5.37
- ----------------------------------------------------------------------------------------------------
Coal
2001 1.23 1.27 0.64 0.55 0.94 0.64
2005 0.92 0.97 0.27 0.21 0.72 0.27
2010 0.96 0.94 0.27 0.22 0.70 0.27
2015 0.94 0.89 0.27 N/A 0.22 0.71 0.27
2020 0.92 0.84 0.28 0.23 0.73 0.28
Levelized Average
(2001-2020)
1.02 1.04 0.36 0.30 0.78 0.36
- ----------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
94 [LOGO] ICF CONSULTING
Exhibit 5-8 (continued)
Summary of Key Modeling Assumptions - Base Case
- ----------------------------------------------------------------------------------------------------
Treatment
Parameter -------------------------------------------------------------------------------
PJM NEPOOL ComEd LILCO Montana AZ/NM PacNW
- ----------------------------------------------------------------------------------------------------
Non-Utility
(MW)
Dispatchable 2,744 2,167 159 0 82 671
Non- N/A
Dispatchable 1,273 671 150 43 3 555
Total 4,017 2,838 309 43 85 1,226
- ----------------------------------------------------------------------------------------------------
SO2 Regulations Phase II Acid Rain - no tightening of current legislation assumed
- ----------------------------------------------------------------------------------------------------
NOx Regulations NOx OTR, AND NOx SIP Call modeled
- ----------------------------------------------------------------------------------------------------
CO2 Regulations Not modeled
- ----------------------------------------------------------------------------------------------------
Mercury Regulations Not modeled
- ----------------------------------------------------------------------------------------------------
Allowance Prices SO2 NOx(9)
(1998$/ton) --- ------
2001 206 985
2005 252 1,921
2010 352 2,681
2015 580 3,572
2020 580 3,572
- ----------------------------------------------------------------------------------------------------
Import Capability(10) (GW) Export Capability(10) (GW)
-------------------------- --------------------------
PJM 21.8 23.9
NEPOOL 1.5 1.9
ComEd 5.4 7.7
LILCO 2.1 2.3
Montana 2.4 3.4
Arizon/New Mexico 4.2 9.4
PacNW 11.4 12.3
- ----------------------------------------------------------------------------------------------------
1 To account for historical forecast error, ICF has reviewed NERC's demand
forecasts and determined the average forecast error percentages over
roughly the last 20 years. ICF's current forecasts are based on the NERC
ES&D 2000 vintage projection and adjusted for historical forecast error.
2 Values shown are weather normalized.
3 Adjusted for summer regional conditions.
4 Assumes an 11.2 percent real discount rate.
5 Weighted average by sub-regional peak demand for PJM East, South, and West
shown.
9 2000-2201 OTR allowance prices are assumed to be $1,000 based on current
market activity.
10 Includes inter-regional and intra-regional.
Natural Gas Prices
Over time, natural gas plays an increasingly important role in determining
power prices as new combined cycle and combustion turbine units increasingly
constitute marginal unit on the system.
We believe that recent prices, i.e., during the 1990s after deregulation,
are much more representative of the future than those for pre-1985, especially
1970 to 1985, when regulatory distortions were at their height. This
notwithstanding, late 2000/early 2001 gas prices have been well above recent
averages.
- --------------------------------------------------------------------------------
95 [LOGO] ICF CONSULTING
Exhibit 5-9
Historical Natural Gas Wellhead Prices (1940-1994)
[GRAPH]
U.S. natural gas prices have increased significantly in real terms over
the last 50 to 60 years (see Exhibit 5-9). This is reflective of depletion of
resources as well as trends such as the decreasing importance of associated gas
- - i.e., a by-product of oil production. In the 1970s and early 1980s, natural
gas prices were superheated by two key developments: (i) U.S. government
wellhead price controls which became binding by 1970 and inhibited supply, and
(ii) oil price increases which increased demand just as supply was being
throttled by the US Government.
In the late 1980s, regulatory controls were relaxed leading to price
drops. Throughout the 1990s, prices were generally maintained around $2.50/MMBtu
on average. This occurred even during the oil price spikes of 1990 - 1991. At
this time, the supply response to price spikes was so strong the industry was
considered to have excess (a.k.a. the "gas bubble".) Also at this time, Henry
hub became the benchmark for North American gas prices and the location for the
dominant futures contract in North America. In 2000, a large price spike
occurred, doubling the annual average price at Henry Hub.
ICF believes that recent prices, i.e., during the 1990s after deregulation
are much more representative of the future than those for pre-1985, especially
1970 to 1985, when regulatory distortions were at their height.
- --------------------------------------------------------------------------------
96 [LOGO] ICF CONSULTING
Exhibit 5-10
Historical Henry Hub Prices (2000$)
[GRAPH]
Over the last several months, natural gas prices have increased to record
highs on the order of $8 - $10/MMBtu (nominal). Annual average prices reached
about $4.00/MMBtu (1998$) in 2000 (actually about $4.35/MMBtu), even above the
$3.9/MMBtu seen in 1982. In part, high gas prices are related to the crude and
product oil prices which are at extremely high levels (see Exhibits 5-11 and
5-12). This is because there is switchable demand which will be willing to pay
more for gas when oil prices are high. This requires, of course, a tight gas
demand and supply situation, especially considering the increasingly small
amount of fungible fuel use over time. We believe oil prices are not sustainable
at these high levels, and hence, believe oil prices will soon fall and gas
prices will return to equilibrium levels over the next few years.
- --------------------------------------------------------------------------------
97 [LOGO] ICF CONSULTING
Exhibit 5-11
Crude Oil Prices are the Highest Since 1990 WTI Cushing, OK (Nominal$/BBl)
[GRAPH]
Exhibit 5-12
Long-Term Correlation Between Crude Oil Prices and Natural Gas Prices 1980-1999
(1998$/MMBtu)
[GRAPH]
- --------------------------------------------------------------------------------
98 [LOGO] ICF CONSULTING
The tight gas demand and supply situation is partly explained by three
additional factors: (1) rising natural gas demand from power plants, (2) the
fall in natural gas drilling that resulted after the low oil prices in 1998 (see
Exhibit 5-13), and (3) to extreme weather conditions. November-December 2000 was
the coldest in U.S. history. Prior to this large price increase, there was no
clear evidence or expectations that such a movement would result. This is
associated with the difficulties in assessing well deliverability. However, ICE
has modeled 17,000 U.S. and Canadian reservoirs using its NANGAS system, as
discussed below.
Many observers prefer to use current futures (or forward) prices to
describe natural gas prices. Futures can be appropriate in situations in which
all elements of the assessment have been contracted forward. In such a case. the
risk free interest rate is used. Note, even weather needs to be contracted. In
this forecast, only forecasts should be used as should a risk adjusted discount
rate. We also show that forward prices are not predictive for all except the
extremely short term. They simply correlate with current spot prices.
Exhibit 5-13
U.S. Natural Gas Rig Count
[GRAPH]
As can be seen, there has been a considerable pickup in recent drilling
activity. While we anticipate continued tight market conditions for the
near-term, we expect market conditions to return to equilibrium within the next
2 to 3 years.
ICE's natural gas price forecasts were derived from results from ICE's
North American Natural Gas Analysis System (NANGAS). The NANGAS model has
descriptive and analytic capability that allows assessment of gas resources and
markets from reservoir to burner-tip, working from a database of more than
17,000 US and Canadian reservoirs.
- --------------------------------------------------------------------------------
99 [LOGO] ICF CONSULTING
Exhibit 5-14
ICF Henry Hub Price Projections (Nominal$)
[GRAPHIC]
The NANGAS model also contains: explicit characterizations of the
performance and market penetration rate of E&P technologies; detailed
regional/sectoral/seasonal demand criteria; site-specific investment, operating
and environmental compliance cost; and a pipeline network simulation that
analyzes supply, demand, and transportation interactions consistently and
comprehensively. We believe that large amounts of low cost resources exist in
the U.S. and that gas prices will be driven by the costs of exploration and
production.
Thus, it can be considered roughly happenstance that the historical
trendline and our forecast go together. The key is that there will be strong
nominal prices in the future due to growing demand and the need to use more
expensive sources even after technological improvement is considered.
- --------------------------------------------------------------------------------
100 [LOGO] ICF CONSULTING
Exhibit 5-15
NYMEX Futures versus ICF Gas Price Forecast
[GRAPH]
The above notwithstanding, current futures prices for natural gas are very
strong (see Exhibit 5-15). Natural gas futures show Henry Hub Louisiana market
prices at roughly $4/MMBtu (real 1998$) through Summer 2003. The current tight
market conditions are reflected in our high natural gas price forecast for 2001
of $5/MMBtu (2000$) at Henry Hub in the Base Case. However, ICF believes that
current oil prices cannot be sustained and that as they fall, the natural gas
market will also return to equilibrium levels. Indeed, ICF forecasts a return to
equilibrium by 2005 with gas at Henry Hub at about $2.7/MMBtu (1998$)
representing a decline of nearly 15 percent per year.
Although gas prices rise over time in nominal terms, they do not increase
in real terms after 2005 despite continued increase in demand, especially from
the power sector. Discovery of new resources combined with technological
improvements and lower real drilling costs offsets rising demand (see Exhibit
5-16).
- --------------------------------------------------------------------------------
101 [LOGO] ICF CONSULTING
Exhibit 5-16
ICF Base Case Forecast ($/MMBtu)
[GRAPH]
We emphasize that our forecast accounts for rising natural gas demand.
Specifically, U.S. demand for natural gas is expected to increase 32 percent
between now and 2010 with most of the increase to come from electric generators
and industrial customers. We also emphasize there can be disequilibrium
conditions around this trend (see Exhibit 5-17).
- --------------------------------------------------------------------------------
102 [LOGO] ICF CONSULTING
Exhibit 5-17
Natural Gas Outlook
[GRAPH]
The gas market analysis assumes there is a single market-clearing price
for spot delivered gas in all periods. In other words, all gas is "firm" in that
the price is enough to ensure delivery (i.e., there are no liquidity problems)
though consumers can decide not to purchase during peak periods. Gas prices are
also modeled as varying by season. The seasonality reflects variation in both
commodity and transportation prices. As gas consumption is largely driven by
heating requirements, winter prices are typically higher than summer prices.
However, given growing summer demand from the power sector, the projected
seasonal spread is lower than the historical seasonal spread.
- --------------------------------------------------------------------------------
103 [LOGO] ICF CONSULTING
Exhibit 5-18
Henry Hub Historical and Forecast Prices - Real 1998$
[GRAPH]
Source: Historical data from Natural Gas Week; forecast data for Base and
Low Case represent ICF forecasts. High Case combines near-term forward
market expectations and long-term ICF High Price expectations.
Beyond 2005, natural gas prices are expected to recover in response to
continued increase in demand, especially from the power sector. Natural gas
prices are forecasted to increase around 1.5 percent annually through 2020.
- --------------------------------------------------------------------------------
104 [LOGO] ICF CONSULTING
Exhibit 5-19
Delivered Natural Gas Prices - Base Case
- --------------------------------------------------------------------------------
Annual Average Price (1998$/MMBtu)
Year ------------------------------------------------------
PJM West NEPOOL Montana Arizona PacNW
- --------------------------------------------------------------------------------
Commodity - Henry Hub
2001 4.99
2005 2.68
2010 2.75
2015 2.64
2020 2.54
- --------------------------------------------------------------------------------
Basis Differential
2001 0.23 0.62 0.10 0.35 0.01
2005 0.23 0.52 0.05 0.12 0.03
2010 0.28 0.60 -0.12 0.15 0.07
2015 0.44 0.80 -0.36 -0.10 -0.16
2020 0.65 0.91 -0.43 -0.16 -0.50
- --------------------------------------------------------------------------------
Total Delivered
2001 5.22 5.61 5.09 5.34 5.00
2005 2.92 3.20 2.73 2.80 2.71
2010 3.03 3.35 2.63 2.91 2.82
2015 3.08 3.44 2.28 2.54 2.48
2020 3.19 3.45 2.11 2.38 2.04
- --------------------------------------------------------------------------------
Levelized Average(1) 3.48 3.80 3.11 3.32 3.15
- --------------------------------------------------------------------------------
1 Levelized using an 11.2 percent real discount rate.
Source: ICF, unless otherwise noted.
- --------------------------------------------------------------------------------
105 [LOGO] ICF CONSULTING
Exhibit 5-20
Delivered Natural Gas Prices - Downside Case
- --------------------------------------------------------------------------------
Annual Average Price (1998$/MMBtu)
Year ------------------------------------------------------
PJM West NEPOOL Montana Arizona PacNW
- --------------------------------------------------------------------------------
Commodity - Henry Hub
2001 4.37
2005 2.28
2010 1.96
2015 2.09
2020 2.04
- --------------------------------------------------------------------------------
Basis Differential
2001 0.23 0.61 0.11 0.31 0.06
2005 0.25 0.52 0.15 0.24 0.13
2010 0.33 0.75 -0.17 0.16 -0.20
2015 0.44 0.83 -0.44 -0.12 -0.55
2020 0.59 0.80 -0.41 -0.25 -0.55
- --------------------------------------------------------------------------------
Total Delivered
2001 4.60 4.98 4.48 4.67 4.43
2005 2.53 2.80 2.44 2.53 2.35
2010 2.29 2.71 1.78 2.12 2.09
2015 2.53 2.92 1.65 1.97 1.89
2020 2.63 2.83 1.63 1.78 1.49
- --------------------------------------------------------------------------------
Levelized Average(1) 2.89 2.74 2.67 2.88 2.64
- --------------------------------------------------------------------------------
1 Levelized using an 11.2 percent real discount rate.
Source: ICF, unless otherwise noted.
In the Low Price Case, prices decline at 1.8 percent annually in real
terms through 2020. As in the Base Case, there is also a sharp drop through 2005
followed by 1.6 percent annual real increase through 2010. Gas prices in the
High Price Case fall from current levels through 2005, but recover by 2010 to
substantially higher real levels. Prices in nominal terms, of course, are much
higher than shown here in all three cases.
- --------------------------------------------------------------------------------
106 [LOGO] ICF CONSULTING
Exhibit 5-21
Delivered Natural Gas Prices - High Case
- --------------------------------------------------------------------------------
Annual Average Price (1998$/MMBtu)
Year ------------------------------------------------------
PJM West NEPOOL Montana Arizona PacNW
- --------------------------------------------------------------------------------
Commodity - Henry Hub
2001 5.53
2005 3.34
2010 3.53
2015 3.46
2020 3.23
- --------------------------------------------------------------------------------
Basis Differential
2001 0.25 0.67 0.12 0.36 0.06
2005 0.27 0.61 0.15 0.16 0.04
2010 0.28 0.65 -0.10 0.12 0.14
2015 0.32 0.67 -0.14 0.09 0.06
2020 0.54 0.91 -0.29 -0.15 -0.44
- --------------------------------------------------------------------------------
Total Delivered
2001 5.78 6.20 5.65 5.89 5.59
2005 3.62 3.96 3.50 3.51 3.38
2010 3.81 4.18 3.43 3.65 3.67
2015 3.77 4.13 3.31 3.55 3.52
2020 3.78 4.14 2.95 3.08 2.79
- --------------------------------------------------------------------------------
Levelized Average(1) 4.13 4.49 3.87 4.02 3.90
- --------------------------------------------------------------------------------
1 Levelized using an 11.2 percent discount rate.
Source: ICF, unless otherwise noted.
High Case forecasts were developed using the NYMEX futures strip prices as
of October 10, 2000. In the near-term, 2001-2003, the NYMEX price quotes for
Henry Hub are higher than the standard ICF High Case projections and reflect the
upper level on potential spot gas markets. Beyond 2003, the futures quotes are
limited, and actually drop below standard ICF High Case projections. The High
Case used in this modeling exercise represents a combination of the NYMEX
futures quotes through 2003 and the ICF standard High Case forecast thereafter.
This is due in large part to current oil market fluctuations. Beyond 2003,
futures strip trading is very weak, therefore, we default to the ICF High Case
forecast for the mid- and long-term periods.
The gas market analysis assumes there is a single market-clearing price
for delivered gas in all periods. In other words, all gas is "firm" in that the
price is enough to ensure delivery (i.e., there are no liquidity problems)
though consumers can decide not to purchase during peak periods. The seasonality
reflects variation in both commodity and transportation prices. ICF computed
average price across four seasons and these average seasonal price differentials
are presented in Exhibit 5-22 and 5-23.
- --------------------------------------------------------------------------------
107 [LOGO] ICF CONSULTING
Exhibit 5-22
Delivered Gas Price Seasonality - Eastern Interconnect
--------------------------------------------------------------------------
Delivered Natural Gas Differential from
Season(1) Annual Average (1998$/MMBtu)
-------------------------------------------
PJM West NEPOOL
--------------------------------------------------------------------------
Summer -0.16 -0.19
--------------------------------------------------------------------------
Winter +0.26 +0.32
--------------------------------------------------------------------------
Other -0.13 -0.16
--------------------------------------------------------------------------
Shoulder -0.01 -0.01
--------------------------------------------------------------------------
1 Seasons are defined as:
Summer - June, July, August
Winter - December, January, February
Other - May, September
Shoulder - March, April, October, November
Source: Natural Gas Week, 1994 - 1997 average based on season
definitions.
Exhibit 5-23
Delivered Gas Price Seasonality - WSCC
--------------------------------------------------------------------------
Delivered Natural Gas Differential from
Season(1) Annual Average (1998$/MMBtu)
---------------------------------------------
Montana Arizona PacNW
--------------------------------------------------------------------------
Winter +0.22 +0.14 +0.07
--------------------------------------------------------------------------
Hydro Peak -0.09 -0.08 -0.05
--------------------------------------------------------------------------
Load Peak -0.16 -0.05 +0.02
--------------------------------------------------------------------------
September -0.16 -0.05 +0.02
--------------------------------------------------------------------------
Fall -0.06 -0.09 -0.09
--------------------------------------------------------------------------
1 Seasons defined as:
Winter - January, February, March
Hydro Peak - April, May June
Load Peak - July August
September - September
Fall - October, November
Oil Prices
Oil prices are generally less important in PJM than NEPOOL. NEPOOL has a
relatively large population of oil/gas steam units that can switch between these
fuels as the economics dictate. The northeast and Florida are the largest
consumers of oil for electric power production.
Within NEPOOL, a large number of new units using gas turbine technology in
combined cycle are coming on line in the near-term. Recent expansions in natural
gas pipeline capabilities have provided NEPOOL the ability to support the
capacity expansion and to continue to grow. Hence, the reliance on fuel oil is
expected to fall as new gas-fired combined cycle units come online. Existing
units are expected to continue to base fuel decisions on economics and do have
options to switch fuel in our modeling. Note, however, gas/pipeline expansion
into New England is substantial, but may not fully keep pace with new combined
cycle additions. Further, not all of these units can burn distillate. Thus,
near-term gas price fly-ups are possible.
- --------------------------------------------------------------------------------
108 [LOGO] ICF CONSULTING
Exhibit 5-24
Commodity Oil Prices Forecasts (1998$/Bbl)
------------------------------------------------------------
All Cases
------------------------------------------------------------
Crude(1)
2001 24.9
2005 20.6
2010 20.6
2015 20.6
2020 20.6
Levelized Average 22.1
------------------------------------------------------------
Gulf Coast Residual 1%
2001 23.0
2005 19.1
2010 19.2
2015 19.2
2020 19.2
Levelized Average 20.6
------------------------------------------------------------
Gulf Coast Distillate
2001 27.7
2005 23.6
2010 23.6
2015 23.6
2020 23.6
Levelized Average 25.1
------------------------------------------------------------
Exhibit 5-25
Delivered 1 Percent Residual Oil Prices by Region and Case (1998$/Bbl)
- --------------------------------------------------------------------------------
Year PJM
East/South PJM West NEPOOL Montana AZNM PACNW
- --------------------------------------------------------------------------------
2001 23.6 23.7 23.6 25.7 26.3 29.7
2005 20.5 20.7 20.5 21.8 22.4 25.8
2010 21.4 21.5 21.4 21.9 22.5 25.9
2015 22.2 22.3 22.2 21.9 22.5 25.9
2020 22.2 22.3 22.2 21.9 22.5 25.9
- --------------------------------------------------------------------------------
Exhibit 5-26
Delivered Distillate Prices by Region and Case (1998$/Bbl)
- --------------------------------------------------------------------------------
Year PJM
East/South PJM West NEPOOL Montana AZNM PACNW
- --------------------------------------------------------------------------------
Source/ Gulf New York New York Gulf Gulf Gulf
Basis: Coast Harbor Harbor Coast Coast Coast
- --------------------------------------------------------------------------------
2001 29.4 30.8 30.8 33.8 30.0 33.8
2005 25.3 26.7 26.7 29.7 25.9 29.7
2010 25.3 26.7 26.7 29.7 25.9 29.7
2015 25.3 26.7 26.7 29.7 25.9 29.7
2020 25.3 26.7 26.7 29.7 25.9 29.7
- --------------------------------------------------------------------------------
Oil/gas steam units in both PJM and NEPOOL are provided the option to burn
oil or gas. When burning oil, units have an incremental SO(2) allowance price
adder that is not applicable
- --------------------------------------------------------------------------------
109 [LOGO] ICF CONSULTING
when burning gas. Residual oil prices are often slightly below gas prices
excluding environmental costs.
Many combined cycles and combustion turbines are capable of burning both
gas and distillate, however due to the higher cost of distillate, gas is
generally the more economic.
Coal Prices
Exhibit 5-27
U.S. Coal Supply Regions
[GRAPHIC]
- --------------------------------------------------------------------------------
110 [LOGO] ICF CONSULTING
Exhibit 5-28
50-Year Historical Average Coal Prices
[GRAPHIC]
Source: EIA Annual Energy Review
Unlike gas, coal prices have decreased in real terms over the last 50
years. This reflects: (i) increased economies of scale especially in surface
mining in the West; (ii) new technologies, especially longwall mining; (iii)
improved technology in such areas as continuous mining; and (iv) lower
transportation costs facilitating access to lower minemouth cost coal.
Even so, over the last 50 years, there have been some significant price
swings in annual average domestic coal prices.
o Through the late 1960s, real coal prices were decreasing while
nominal prices were relatively flat.
o In the early and mid 1970s, real and nominal coal prices
increased sharply in response to crude oil and natural gas
price movements.
o Thereafter, real prices experienced fairly substantial rates
of decline through recent periods. In the late 1990s, the
downward real price trend does seem to slow.
o There has been a kick-up in coal prices in recent months
reflecting tight coal market conditions and in part
attributable to high gas and oil price conditions.
- --------------------------------------------------------------------------------
111 [LOGO] ICF CONSULTING
Exhibit 5-29
Coal Mine Labor Productivity Improvement Over Time
[GRAPH]
Rapid labor productivity growth has been continuing even recently.
Productivity growth continues throughout the forecast though we expect it to
slow. We assume declining coal prices in real terms due to continued
improvements in productivity such that prices are relatively unchanged on a
nominal basis.
Exhibit 5-30 shows the annual trend in coal prices between 1998 and 2000.
2001 values represent the weekly minemouth coal prices reported for
year-to-date. The pricing trend in 2001 has been quite steep and is expected to
continue at high levels for the near-term before declining to normal equilibrium
levels.
Exhibit 5-30
Historical Central Appalachian Coal Price
[GRAPH]
Note: Central Appalachian Coal Price, 1% Sulfur, 25 MMBtu/ton (12,500)
Source: Coal Week; 2001 Prices are through May 2001
- --------------------------------------------------------------------------------
112 [LOGO] ICF CONSULTING
The Central Appalachian coal price declined significantly through the
1990s. Between 1993 and 1998, prices decreased by more than 15 percent in real
terms. The price for Central Appalachian low-sulfur coal was not affected upward
by utility Phase I Acid Rain compliance that went into effect in January 1995.
This was because of the flexibility the utilities had for complying with Phase I
regulation including switching to low-sulfur coal, purchasing SO(2) allowances,
and coal blending. Productivity increases and intense competition from Powder
River Basin and Northern Appalachia coals are key factors that have prevented
the price for Central Appalachian coal from increasing until recently.
Our forecast for 2001 and 2002 shows above equilibrium prices for coal,
especially low sulfur Appalachian coal. Thereafter, coal prices reflect
equilibrium conditions and we assume declining coal prices in real terms due to
continued improvements in productivity such that prices are relatively unchanged
on a nominal basis. This analysis also assumes that coal markets remain as
competitive as they are at present, which is a likely outcome, but not the only
outcome. In a competitive market, coal purchased under long term contracts at
above market prices cannot be intentionally recovered. As such, we expect that
when plant owners operate and bid, they will price coal at current market
conditions.
Representative minemouth coal price forecasts are shown in Exhibit 5-31.
ICF models transportation from minemouth to burnertip on a plant-by-plant basis
throughout the U.S. Delivered fuel prices at the PPL stations are provided in
the unit level assumptions chapter.
Exhibit 5-31
Minemouth Coal Prices at Representative Plants
- ---------------------------------------------------------------------------------------
Central Central
Coal Prices - Appalachian Pennsylvania Bailey PRB
Minemouth (0.7% S, 12,000 (1.5-2.0% S, (1.4% S, 13,000 0.5% S, 17,000
(1998$/ton) Btu/lb) 12,500 Btu/lb) Btu/lb) Btu/lb
- ---------------------------------------------------------------------------------------
2000 30.6 30.8 36.6 9.4
2005 23.3 23.0 25.2 3.7
2010 22.6 23.9 26.1 3.7
2015 21.4 23.4 26.7 3.8
2020 20.2 22.9 27.3 3.9
- ---------------------------------------------------------------------------------------
Coal units make up a substantial portion of the PJM West capacity mix
although they are less important in PJM East, PJM South, and NEPOOL. PJM West
has access to several coal sources which are in very close proximity to the PPL
coal units. The most important coal types in PJM are Central Pennsylvania mid
sulfur coal, Monongahela "Bailey type" coal (1.5 percent sulfur), and Southern
West Virginia/East Kentucky compliance coal in Eastern PJM.
The PPL Montana coal units are located centrally to the PRB coal mines and
have very low coal costs.
We assume declining coal prices in real terms due to continued
improvements in productivity such that prices are relatively unchanged on a
nominal basis. This analysis also assumes that coal markets remain as
competitive as they are at present, which is a likely outcome, but not the only
outcome. In a competitive market, coal purchased under long term
- --------------------------------------------------------------------------------
113 [LOGO] ICF CONSULTING
contracts at above market prices cannot be intentionally recovered. As such, we
expect that when plant owners operate and bid, they will price coal at current
market conditions.
Nominal rail costs have declined in recent years. In contrast, general
inflation has continued at average levels. We forecast a 2 percent decrease in
real rail costs. We also assume that coal on coal competition will continue in
the Wyoming PRB and that rail on rail competition will continue between Union
Pacific and Burlington Northern railroads. This does not directly affect PJM
coal that is mostly from Appalachia, but indirectly puts downward price pressure
on Central Appalachia minemouth coal prices.
Environmental Compliance
The Environmental Protection Agency (EPA) serves "to protect human health
and to safeguard the natural environment." Under this mission, EPA has as a goal
of ensuring clean air such that the air in every American community will be safe
and healthy to breathe and that individuals with respiratory ailments will be
protected from health risks of breathing polluted air. Two of the largest
contributing components of air pollution are SO(2) and NO(x). Exposure to high
concentrations of SO(2) can lead to health problems, such as respiratory illness
and aggravation of cardiovascular disease, while NO(x) emissions contribute to
the formation of ground level ozone or smog, which is a primary human health and
environmental concern. In addition, both SO(2) and NO(x) emissions are
precursors of acid deposition or acid rain. Because of these adverse effects,
SO(2) and NO(x) are regulated by EPA as two of the six criteria pollutants under
the National Ambient Air Quality Standards (NAAQS).
SO(2) emissions primarily arise from combustion processes and are largely
dependent on the sulfur content of fuels burned. NO(x) emissions also rise from
the combustion process, but depend on both combustion technology and nitrogen
content of fuels. The electric power industry is one of the largest sources of
SO(2) and NO(x) emissions in the U.S. Hence, current and future regulations of
these air pollutants have significant impact on the capacity expansion and
dispatch decisions of the electric power generators. Further, prospective
regulations that affect SO(2), NO(x), or other air pollutants (such as mercury)
emitted by the power plants pose considerable risks and opportunities to
electric power generating asset owners.
The applicable air emission regulations that affect SO(2) and NO(x)
emissions in PJM and Southern ECAR are briefly described in two subsequent
sections: (1) Existing Air Emission Regulations; and (2) Potential Air Emission
Regulations. Note that both regions are currently impacted by SO(2) emissions
restrictions, but only PJM is subject to existing NO(x) legislation.
The impacts of federal air emission regulations on SO(2) and NO(x)
emissions are described below.
SO(2) Regulations
Title IV of the Clean Air Act Amendments (CAAA) of 1990 requires that
overall annual SO(2) emissions be reduced by 10 million tons below 1980 levels
in the contiguous United States. To achieve these reductions, the law requires
placing a two-phase SO(2) emission restriction on fossil fuel-fired power
plants.
- --------------------------------------------------------------------------------
114 [LOGO] ICF CONSULTING
Phase I, which began in 1995, initially affected 261 highest emitting
generation units with at least 100 MW of capacity at 110 mostly coal-burning
electric utility plants located in 21 Eastern and Midwestern States. An
additional 174 units were added to Phase I of the program later, bringing the
total number of Phase I affected units to 435. The SO(2) emission limits (or
allowance allocations) for these units are calculated by multiplying the SO(2)
rate of 2.5 lbs per MMBtu by the "baseline" (1985-87) average fuel consumption.
Each SO(2) allowance entitles the owner of the affected unit to emit one ton of
SO(2) annually.
Phase II, which began 2000, required all utility fossil fuel units with
capacity greater than 25 MW to reduce their SO(2) emissions. For most existing
coal units, SO(2) emission limits (or allowance allocations) are determined
based on an SO(2) rate of 1.2 lbs per MMBtu multiplied by their baseline fuel
consumption. Allowances are allocated only for existing units. New units will
have to buy allowances in the market to offset their SO(2) emissions.
This program represents a dramatic departure from traditional command and
control regulatory methods that establish specific, inflexible emissions
limitations that all affected sources must comply to. The allowance trading
system introduced under this program harnesses the incentive of the free market
to meet pollution reduction goals.
The SO(2) emission restrictions can be met either by reducing emissions or
buying allowances from other sources. Allowances may be transferred among units
in the same system, banked for future use in later years, and bought and sold
between systems and across state lines. However, a utility must have enough
allowances each year to cover actual emissions. If annual emissions exceed the
number of allowances held, the owners or operators of delinquent units must pay
a penalty of $2,000 (adjusted for inflation using 1995 as the base year) per
excess ton of SO(2).
Also note that under this system, affected utility units were allocated
allowances based on their historic fuel consumption and a specific emission
rate. Each allowance permits a unit to emit one ton of SO(2) during or after a
specified year. For each ton of SO(2) discharged during a given year, one
allowance is retired, that is, it can no longer be used. Allowances may be
bought, sold or banked. Any person may acquire allowances and participate in the
trading system. However, regardless of the number of allowances a source holds,
it cannot emit at levels violating federal or state limits set under Title I of
the Clean Air Act to protect public health.
During Phase II of the program, a permanent ceiling (or cap) of 8.95
million allowances for total annual allowance allocations to utilities exists.
This cap firmly restricts emissions and ensures that environmental benefits will
be achieved and maintained. The market-based allowance trading system
capitalizes on the power of the marketplace to reduce SO(2) emissions
cost-effectively and uses economic incentives to promote conservation and the
development of innovative technology.
- --------------------------------------------------------------------------------
115 [LOGO] ICF CONSULTING
Exhibit 5-32
Total Annual Phase II SO(2) Allowances for the PPL GenCo Fossil Units
(tons of SO(2))
- --------------------------------------------------------------------------------
Plant 2000 - 2003 2004 - 2020
- --------------------------------------------------------------------------------
Brunner Island 1 & 2 25,378 25,429
- --------------------------------------------------------------------------------
Brunner Island 3 23,201 23,250
- --------------------------------------------------------------------------------
Brunner Island Diesel 0 0
- --------------------------------------------------------------------------------
Conemaugh Coal 1(1) 2,953 2,959
- --------------------------------------------------------------------------------
Conemaugh Coal 2(1) 3,274 3,280
- --------------------------------------------------------------------------------
Keystone 1(1) 3,481 3,488
- --------------------------------------------------------------------------------
Keystone 2(1) 3,706 3,714
- --------------------------------------------------------------------------------
Martins Creek Coal 14,551 14,575
- --------------------------------------------------------------------------------
Martins Creek Steam (oil) 0 0
- --------------------------------------------------------------------------------
Martins Creek Steam (gas) 25,302 25,353
- --------------------------------------------------------------------------------
Martins Creek CT 0 0
- --------------------------------------------------------------------------------
Montour Coal 48,853 48,853
- --------------------------------------------------------------------------------
Lower Mount Bethel 0 0
- --------------------------------------------------------------------------------
Colstrip(1) 5,929 5,486
- --------------------------------------------------------------------------------
Corette 5,060 4,884
- --------------------------------------------------------------------------------
Wyman 4(1) N/A N/A
- --------------------------------------------------------------------------------
1 Represents PPL owned portion only.
Source: PPL.
- --------------------------------------------------------------------------------
116 [LOGO] ICF CONSULTING
SO(2) Allowance Market Trends
Exhibit 5-33
Historical SO(2) Allowance Prices (Nominal $)
[GRAPH]
Phase I and Phase II allowance prices rose sharply in early 1999 in
anticipation of Phase II implementation. According to the emissions allowance
tracking index released by the Clean Air Compliance Review, prices had moved
from the $100/ton range late in 1997 to a high of more than $200/ton in early
1999. However, Phase II allowance prices have fall sharply in the in response to
EPA's New Source Review (NSR) enforcement actions. Recent SO(2) allowance prices
are at about $150 to $175/ton and now show an upward trend. Prices are below
what we believe to be supported by market fundamentals (i.e., the marginal cost
of SO(2) control), due to the expectation of wide-spread scrubbing resulting
from NSR enforcement. Even if widespread scrubbing does occur due to NSR,
allowances for scrubbing units are not likely to be made available to other
affected sources; consequently, the negative impact of scrubber installations on
prices is likely to be muted.
Allowance prices over the long-term will be based on the marginal cost of
reductions in SO(2) emissions in a national marketplace. We project an allowance
price of approximately $213/ton (in real 1998$) in 2000 in the Base Case with
significant real price escalation through 2015.
NO(x) Regulations
Ozone Transport Commission
- --------------------------------------------------------------------------------
117 [LOGO] ICF CONSULTING
The CAAA of 1990 established the Ozone Transport Commission (OTC) to
control NO(x) emissions from 12 Northeastern states, including Pennsylvania, and
the District of Columbia (DC) during the ozone season (i.e., May through
September).(17) These 12 states and DC are collectively referred to as the OTC
states. As a first step towards reducing NO(x) emissions in the OTC states, in
Phase I, stationary sources in these states were required to install Reasonably
Achievable Control Technology (RACT) beginning in 1995. RACT typically
corresponds to low NO(x) burners, or some other form of combustion control
modifications depending on boiler configuration.
Pennsylvania, along with the other OTC states, signed Memorandum of
Understanding (MOU) in September 1994 that created two additional phases for
controlling NO(x) emissions from stationary sources in the northeast.
In Phase II, which began on May 1, 1999, additional NO(x) reductions are
required at electric power plants and industrial boilers with heat inputs
greater than 250 MMBtu/hr during the 5-month summer ozone season, in the Inner
and Outer Zones of OTC. The affected sources located in the Inner Zone are
required to reduce their NO(x) emissions by 65 percent or to 0.2 lbs/MMBtu,
whichever is less stringent. The affected sources located in the Outer Zone are
required to reduce their NO(x) emissions by 55 percent or to 0.2 lbs/MMBtu,
whichever is less stringent. In Pennsylvania, the Inner Zone includes Berks,
Bucks, Chester, Delaware, Montgomery, and Philadelphia counties; and the Outer
Zone includes the remaining counties. Under Phase II, annual NO(x) emissions in
these zones in the OTC will be limited to approximately 220,500 tons (Lion,
1999),(18) which represent a reduction of approximately 55 percent below the
1990 levels. Electric generating units have been allocated approximately 194,100
tons (which accounts for approximately 88 percent of the total NO(x) budget),
with industrial boilers accounting for the remainder of Phase II NO(x) budget
(ICF, 1998).(19)
Phase III, which begins in 2003, requires further reductions in the Inner
and Outer Zones, and also extends NO(x) reductions to include the Northern zone,
in the OTC. The affected sources located in the Inner and Outer Zones (in
Pennsylvania and elsewhere in the OTC) are required to reduce their NO(x)
emissions by 75 percent or to 0.15 lbs/MMBtu, whichever is less stringent, while
affected sources in the Northern Zone (in which no part of Pennsylvania is
located) are required to reduce their NO(x) emissions by 55 percent or to 0.2
lbs/MMBtu, whichever is less stringent. Under Phase III, the annual NO(x)
emissions in the Northeast will be lowered to approximately 143,600 tons (Lion,
1999), which represent a reduction of 35 percent below Phase II levels. Electric
generating units have been allocated approximately 126,200 tons (which accounts
for approximately 88 percent of the total NO(x) budget), with industrial boilers
accounting for the remainder of the Phase III NO(x) budget (ICF, 1998). However,
the Phase III budgets are still subject to revision.
NO(x) reduction requirements vary widely among the OTC states. Variation
in baseline NO(x) rates and Zone location lead to a wide range of percentage
NO(x) reductions in Phase II and Phase III. Under Phase II, annual NO(x)
emissions in Pennsylvania will be lowered to
- ----------
17 The 12 Northeastern states include: Maine, Vermont, New Hampshire,
Massachusetts, Rhode Island, Connecticut, New York, New Jersey,
Pennsylvania, Maryland, Delaware, and Virginia.
18 Lion. 1999. Estimates of Phase II and Phase III total OTC NO(x) allowances
were obtained from Kelly Lion, OTC, in August 1999. Because Virginia has
opted out of this program, the estimates do not include emission limits on
Virginia. Also, please note that the NO(x) allowance estimates reported
are rounded to the nearest hundreds.
19 ICF. 1998. Estimates of Phase II and Phase III NO(x) allowances for
electric generating units are based on ICF's NO(x) Allowance Study,
November 1998. Also, please note that the NO(x) allowance estimates
reported are rounded to the nearest hundreds.
- --------------------------------------------------------------------------------
118 [LOGO] ICF CONSULTING
approximately 93,500 tons (Lion, 1999). Of this total, electric generating units
in Pennsylvania are allowed to emit approximately 86,700 tons (ICF, 1998), which
represent a reduction of approximately 55 percent below the 1990 levels.
Pennsylvania accounts for approximately 42 percent of the total OTC states'
NO(x) budget in Phase II.
Under Phase III, annual allowable NO(x) emissions in Pennsylvania will be
further lowered to approximately 53,000 tons (Lion, 1999). Of this total,
electric generating units in Pennsylvania will be allowed to emit additionally
approximately 49,000 tons (ICF, 1998), which represents a reduction of 43
percent below the Phase II levels. Pennsylvania accounts for approximately 37
percent of the total OTC states' NO(x) budget in Phase III.
Implementation of the Phase II and III emission limits will be through a
cap and trade system. Each source will be allocated a specified number of NO(x)
emission allowances, with an allowance equal to 1 ton of NO(x) emissions.
Individual states will determine how many allowances are to be allocated to each
source.
Implementation of NO(x) OTC Regulations in Pennsylvania
In Pennsylvania, the Department allocates NO(x) allowances to the affected
units based on 1990 baseline emissions for the control period 1999 through 2002.
The owner of each affected source in Pennsylvania is required to hold NO(x)
allowances at least equal to the total NO(x) emitted from the source during that
year's NO(x) allowance control period, by December 31 of that year. The control
period begins on May 1, 1999. The allowances may be transferred to other sources
during the course of a year, according to established procedures. Sources that
are not considered as affected units are also allowed to opt-in. Further, the
Department allocates bonus NO(x) allowances for certain creditable emission
reductions made during the ozone season in 1997 and 1998. For this purpose, only
emission reductions below the Phase II OTC emission limits and any applicable
emission limits, including RACT and Maximum Achievable Control Technology (MACT)
are considered.
Sources that do not have in their account NO(x) allowances equal to or
greater than their NO(x) emissions during the ozone season by December 31 of the
control year will be considered to be in violation. They will be penalized with
3 allowances for each ton of NO(x) emission that was not covered by an
allowance. Accordingly, the penalty allowances will be deducted from their
accounts at the beginning of the subsequent control period, or the sources will
not be allowed to operate. The Phase II OTR NO(x) emission compliance
requirements for affected units in Pennsylvania are described in detail in
Chapter 123 of Title 25 in the Pennsylvania Green Book (1998).
Unlimited banking of NO(x) allowances is allowed. Nonetheless, the use of
such allowances is restricted. If the amount of banked allowances in any year
exceeds 10 percent of the total regional emission cap, any emission withdrawals
in the subsequent period in excess of 10 percent of the cap must be withdrawn on
a 2 for 1 basis. For example, if the total allowances banked in Pennsylvania in
1999 equal 10,500 tons, it exceeds 10 percent (which is approximately 9,350
tons) of Pennsylvania's annual NO(x) budget by 1,150 tons. Therefore, in 2000,
only 9,350 allowances may be withdrawn on a 1 for 1 basis and the remainder of
the allowances may be withdrawn on a 2 for 1 basis. This 10 percent limit is
prorated to each holder of banked allowances. Thus, in 2000, the effective value
of the banked allowances equals 9,925 tons
- --------------------------------------------------------------------------------
119 [LOGO] ICF CONSULTING
[=9,350+ (1,150/2)]. This type of banking and borrowing mechanism is referred to
as "progressive flow control."
Trades will be monitored and confirmed by NO(x) Allowance Tracking System
(NATS). This entails administering transfers of allowances, new accounts, and
the annual reconciliation process whereby account holdings are crosschecked with
emissions on a unit-by-unit basis for compliance determination. The Department's
tracking and auditing procedures are also described in Chapter 123 of Title 25
in the Pennsylvania Green Book (1998).
NO(x) SIP Call and Other Emission Regulations
In addition to the Ozone Transport Region rules applicable in the
Northeast, EPA finalized its Ozone Transport rulemaking on September 24, 1998.
Under this so-called "SIPCall" rule, EPA intends to establish a NO(x) emissions
trading system for 19 eastern states and the District of Columbia. The SIP Call
emission limits are tied to a 0.15 lb/MMBtu emission rate and will yield an
emissions cap approximately equal to the Phase III level for OTR states.
The analysis in this report incorporates the SIP Call effective for the
OTR states in 2003 and the remaining SIP Call states in 2004.
- --------------------------------------------------------------------------------
120 [LOGO] ICF CONSULTING
NOX Market Trends
Exhibit 5-34
Historical NO(x) Allowance Prices (Nominal $)
[GRAPH]
New Source Performance Standards
In addition, new power generating units and industrial boilers are subject
to New Source Performance Standards (NSPS). Under these standards, the new
affected units are required to adopt RACT, Best Achievable Control Technology
(BACT), or Lowest Achievable Emission Rate (LAER) to control their NO(x)
emissions, based on the attainment status of the area in which they are located.
Because the NSPS are applicable to all new units in the U.S., the NO(x)
emissions in Pennsylvania will be affected by these Standards.
In addition to the Ozone Transport Region rules applicable in the
Northeast, EPA finalized its Ozone Transport rulemaking on September 24, 1998.
Under this so-called "SIP Call" rule, EPA intends to establish a NO(x) emissions
trading system for 22 eastern states and the District of Columbia. The SIP Call
emission limits are tied to a 0.15 lb/MMBtu emission rate and will yield an
emissions cap approximately equal to the Phase III level for OTR states. To
date, EPA has not specified how the overlapping OTR and SIP Call NO(x) emission
programs will interact.
- --------------------------------------------------------------------------------
121 [LOGO] ICF CONSULTING
Exhibit 5-35
Post-Combustion NO(x) Controls for Coal Plants (1998$)
- --------------------------------------------------------------------------------------
Fixed Variable
Post-Combustion Capital O&M O&M Percent Percent
Control Technology ($/kW) ($/kW/yr) (mills/kWh) Gas Use Removal
- --------------------------------------------------------------------------------------
SCR
(Low NO(x) Rate) 70.3 6.17 0.25 -- 70
- --------------------------------------------------------------------------------------
SCR
(High NO(x) Rate) 72.4 6.43 0.40 -- 80
- --------------------------------------------------------------------------------------
SNCR
(Low NO(x) Rate) 16.7 0.25 0.82 -- 40
- --------------------------------------------------------------------------------------
SNCR
(High NO(x) Rate - Cyclone) 9.7 0.14 1.27 -- 35
- --------------------------------------------------------------------------------------
SNCR
(High NO(x) Rate - Other) 19.1 0.29 0.88 -- 35
- --------------------------------------------------------------------------------------
Exhibit 5-36
ICF Gas Reburn Technology Characteristics (1998$)
- -----------------------------------------------------------------------------------------------------------
SNCR SCR FLGR AEFLGR
- -----------------------------------------------------------------------------------------------------------
Unit Size (MW) 200 400 200 400 800 200 400 200 400
Capital Cost ($/kW) 16.7 13.1 102.4 83.6 67.6 14.1 9.4 31.0 22.5
Catalyst Cost ($/kW) N/A N/A 8.5 8.7 8.8 N/A N/A N/A N/A
Fixed O&M ($/kW-y) 0.2 0.1 0.5 0.2 0.1 0.1 0.1 0.4 0.2
Variable O&M* ($/MWh) 0.4 0.4 0.5 0.5 0.5 0.0 0.0 0.4 0.4
% Gas Usage N/A N/A N/A N/A N/A 7% 7% 7% 7%
% NO(x) Removal 30 25 85 85 85 35 30 55 45
- -----------------------------------------------------------------------------------------------------------
The ICF cases use post-combustion control costs developed by the U.S.
Environmental Protection Agency (EPA), excluding fuel lean gas reburn and amine
enhanced fuel lean gas reburn. In the SIP Call debate, mid-west utilities have
offered NO(x) pollution control cost estimates significantly higher than ICAC's
and EPA's estimates. Gas reburn assumptions have been derived from recent
projects and industry experience.
The two most prominent post-combustion control technologies available for
reducing NO(x) emissions are selective catalytic reduction (SCR) and selective
non-catalytic reduction (SNCR). SCR is more costly but reduces a larger
proportion of NO(x) emissions (70-80 percent). SNCR is less costly but less
effective (40-50 percent). To date, about 3,000 MW of SCR and 3,200 MW SNCR have
been installed or have been announced. SNCR has been installed only on smaller
units (less than 300 MW) in the OTR. However, plans have been announced to
install
- --------------------------------------------------------------------------------
122 [LOGO] ICF CONSULTING
SNCR on larger units. The relatively small amount of capacity with existing or
announced post-combustion controls suggests that many plant owners have not yet
made final decisions on compliance strategies. This indecision is one of the
factors leading to higher NO(x) allowance prices for 1999. Existing or planned
retrofit decisions will be incorporated into the Base Case. We continually
update our database to reflect announced retrofit decisions, consequently the
ultimate population of planned retrofits is subject to revision.
There are two categories of retrofits that are "hardwired" into this
analysis:
o Existing - Those retrofits where construction has begun.
o Firmly Planned - Those retrofits where solid plans are in place,
equipment is ordered, etc.
All other retrofits will be performed by the model and will be determined
solely based on economics.
Exhibit 5-37
NO(x) Allowance Allocations to PPL GenCo
- --------------------------------------------------------------------------------
Plant 2000 - 2002 (OTR) 2003 and Beyond (SIP Call)
- --------------------------------------------------------------------------------
Brunner Island 1 & 2 2,761 1,286
- --------------------------------------------------------------------------------
Brunner Island 3 2,907 1,539
- --------------------------------------------------------------------------------
Brunner Island Diesel 45 45
- --------------------------------------------------------------------------------
Conemaugh Coal 1(1) 375 247
- --------------------------------------------------------------------------------
Conemaugh Coal 2(1) 517 227
- --------------------------------------------------------------------------------
Keystone 1(1) 494 245
- --------------------------------------------------------------------------------
Keystone 2(1) 392 243
- --------------------------------------------------------------------------------
Martins Creek Coal 1,757 853
- --------------------------------------------------------------------------------
Martins Creek Steam (oil) 0 0
- --------------------------------------------------------------------------------
Martins Creek Steam (gas) 1,574 1,043
- --------------------------------------------------------------------------------
Martins Creek CT 45 45
- --------------------------------------------------------------------------------
Montour Coal 8,265 3,233
- --------------------------------------------------------------------------------
Lower Mount Bethel 0 0
- --------------------------------------------------------------------------------
Total 19,132 9,006
- --------------------------------------------------------------------------------
1 Shown for PPL owned portion only.
Source: PPL.
Other Environmental Regulations
Other regulations not incorporated in our Base Case are possible.
Tightened SO(2) regulations (e.g., tightened PM (particulate) standards,
visibility initiatives, legislative action) could raise allowance prices but our
case already incorporates a dramatic turnaround in SO(2) allowance prices, which
if true, may tend to mitigate the potential for these controls. Importantly,
this analysis does not incorporate the potential for tighter NO(x) controls as
part of the SIP call program.
The largest impact policy and the least likely over the next decade are
significant and binding CO(2) regulations. Kyoto notwithstanding, we have not
incorporated CO(2) controls in our post-2010 analysis. However, if stringent
CO(2) controls are implemented, it could greatly affect
- --------------------------------------------------------------------------------
123 [LOGO] ICF CONSULTING
fuel use patterns in favor of gas over coal even at existing plants, raise gas
prices above forecast levels, and have other major power price consequences.
The reason we have not included these potential regulations is three-fold.
First, these regulations benefit new gas plants like the Facility and we have
attempted to achieve the correct degree of conservativeness. Second, there is
disagreement about the potential for these regulations. Third, the analysis of
these regulations is complex.
Load Growth
Load growth creates the need for new capacity everything else equal. No
builds are economic unless they are needed to meet demand at the super peak.
This supports the pure capacity component of prices.
Load growth is also a determinant of marginal energy costs. In any given
year, higher load levels require the system to call on increasingly expensive
units on the margin, thereby increasing the marginal energy cost. Conversely,
lower load levels generally result in lower marginal energy costs.
In the longer term, however, higher load growth can actually have the
opposite effect in this region. This is somewhat counter-intuitive, but can be
explained as follows. For example, in NEPOOL, the majority of new units will be
combined cycles, which generally act to depress energy prices due to their high
efficiencies and availabilities. Higher load growth results in a greater number
of combined cycle units being built. Conversely, lower load growth tends to
result in slightly higher energy prices in the long run as fewer combined cycles
are built.
Demand growth in the past decade in PJM has averaged approximately 1.8
percent, varying among the sub-regions. NEPOOL has also had a relatively low
demand growth at 1.4 percent. The NERC forecasts for PJM and NEPOOL are
typically lower than the actual experienced but are generally in the appropriate
range. Historical forecasts have ranged from 1.1 to 1.9 percent for PJM and
NEPOOL over the last decade.
In the Western regions, load growth had been relatively strong in many
regions, PACNW and Montana are expected to grow at 2.3 percent annually in the
near-term, in line with recent load growth. Arizona/New Mexico has been
experiencing very high load growth, often with rates above 4.0 percent in any
given year. We project strong growth rates for Arizona/New Mexico in the
near-term at 3.8 percent, with slightly declining rates thereafter.
Historical growth averages are in line with the ICF projections.
Comparisons between NERC forecasts to actual peak and energy levels achieved are
not well aligned and consistently show forecasts to be low. As such, the ICF
methodology for forecasting demand growth has proven more accurate.
- --------------------------------------------------------------------------------
124 [LOGO] ICF CONSULTING
Exhibit 5-38
PJM Electricity Demand Assumptions
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
Peak Demand
2001 Net Internal Demand (MW) 50,193 50,193
Annual Peak Growth (%)
2001 - 2005 2.4 1.5
2006 - 2010 2.1 1.5
2011 - 2020 1.9 1.5
2021 - 2025 1.7 1.5
- --------------------------------------------------------------------------------
Net Energy for Load
2001 Energy (GWh) 264,153 264,153
Annual Peak Growth (%)
2001 - 2005 2.2 1.5
2006 - 2010 2.1 1.5
2011 - 2020 1.9 1.5
2021 - 2025 1.7 1.5
- --------------------------------------------------------------------------------
Source: ICF forecasts derived using historical growth rates and NERC regional
growth projections.
Exhibit 5-39
NEPOOL Electricity Demand Assumptions
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
Peak Demand
2001 Net Internal Demand (MW) 23,517 23,517
Annual Peak Growth (%)
2001 - 2005 2.1 1.5
2006 - 2010 1.9 1.5
2011 - 2020 1.8 1.5
2021 - 2025 1.7 1.5
- --------------------------------------------------------------------------------
Net Energy for Load
2001 Energy (GWh) 125,333 125,333
Annual Peak Growth (%)
2001 - 2005 1.9 1.5
2006 - 2010 1.7 1.5
2011 - 2020 1.7 1.5
2021 - 2025 1.6 1.5
- --------------------------------------------------------------------------------
Source: ICF internal forecasts derived using historical growth rates and NERC
regional growth projections.
- --------------------------------------------------------------------------------
125 [LOGO] ICF CONSULTING
Exhibit 5-40
Montana Electricity Demand Assumptions
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
Peak Demand
2001 Net Internal Demand (MW) 2,091 2,091
Annual Peak Growth (%)
2001 - 2005 2.3 1.6
2006 - 2010 2.2 1.6
2011 - 2020 2.0 1.6
2021 - 2025 1.8 1.6
- --------------------------------------------------------------------------------
Net Energy for Load
2001 Energy (GWh) 13,065 13,065
Annual Peak Growth (%)
2001 - 2005 2.0 1.6
2006 - 2010 1.9 1.6
2011 - 2020 1.8 1.6
2021 - 2025 1.7 1.6
- --------------------------------------------------------------------------------
Source: ICF internal forecasts derived using historical growth rates and NERC
regional growth projections.
Exhibit 5-41
AZNM Electricity Demand Assumptions
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
Peak Demand
2001 Net Internal Demand (MW) 17,571 17,571
Annual Peak Growth (%)
2001 - 2005 3.8 3.2
2006 - 2010 3.6 3.2
2011 - 2020 3.5 3.2
2021 - 2025 3.3 3.2
- --------------------------------------------------------------------------------
Net Energy for Load
2001 Energy (GWh) 89,613 89,613
Annual Peak Growth (%)
2001 - 2005 3.9 3.2
2006 - 2010 3.7 3.2
2011 - 2020 3.6 3.2
2021 - 2025 3.4 3.2
- --------------------------------------------------------------------------------
Source: ICF internal forecasts derived using historical growth rates and NERC
regional growth projections.
- --------------------------------------------------------------------------------
126 [LOGO] ICF CONSULTING
Exhibit 5-42
PacNW Electricity Demand Assumptions
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
Peak Demand
2001 Net Internal Demand (MW) 27,682 27,682
Annual Peak Growth (%)
2001 - 2005 2.3 1.6
2006 - 2010 2.2 1.6
2011 - 2020 2.0 1.6
2021 - 2025 1.8 1.6
- --------------------------------------------------------------------------------
Net Energy for Load
2001 Energy (GWh) 192,012 192,012
Annual Peak Growth (%)
2001 - 2005 2.0 1.6
2006 - 2010 1.9 1.6
2011 - 2020 1.8 1.6
2021 - 2025 1.7 1.6
- --------------------------------------------------------------------------------
Source: ICF internal forecasts derived using historical growth rates and NERC
regional growth projections.
Reserve Margin
Generally, a lower reserve margin results in fewer capacity additions.
Conversely, a higher reserve margin would result in greater capacity additions.
This is because the assumption about entry is that the market is on average in
balance - i.e., builds are to reserve requirement levels. As capacity additions
in NEPOOL and parts of PJM are comprised in large part of combined cycles,
greater additions resulting from a higher reserve margin tend to depress energy
prices somewhat. Conversely, a lower reserve margin tends to increase energy
prices as less combined cycles are built and, in any given hour, there is a
greater chance that more expensive units will be required to meet demand.
Exhibit 5-43
Forecast Reserve Margin by Region - All Cases
- --------------------------------------------------------------------------------
Years PJM NEPOOL AZNM Montana PacNW
- --------------------------------------------------------------------------------
2001 19.0 18.0 15.0 15.0 15.0
- --------------------------------------------------------------------------------
2005 17.8 17.0 15.0 15.0 15.0
- --------------------------------------------------------------------------------
2010 - 2020 15.0 15.0 15.0 15.0 15.0
- --------------------------------------------------------------------------------
Planning reserve margins combined with peak load growth determine the
demand for megawatts. It is extremely rare for new power plant construction to
be economic except when the reserve margin is binding.
Currently, a 19.0 percent planning reserve margin is utilized in PJM. ICF
expects that this requirement will fall over time to a stable level of 15
percent by 2010. This expectation is based in part on expectations of more
reliable units replacing large and unreliable units currently in the capacity
mix. NEPOOL currently operates under an 18 percent reserve margin. Similarly,
ICF forecasts this requirement to fall to a stable level of 15 percent by 2010.
The WSCC regions experience load diversity and have significant
transmission capacity across regions. In fact, the transmission grid was in part
designed to take advantage of non-coincident peak situations by allowing for the
more winter peaking regions to export capacity in the summer seasons and
vice-versa. This is an advantage to many areas, but is not sufficient to
- --------------------------------------------------------------------------------
127 [LOGO] ICF CONSULTING
reduce reserve margins to very low levels. We maintain a 15 percent planning
reserve margin for Arizona/New Mexico, Montana, and PACNW.
New Unit Characteristics - Unplanned Builds
Characteristics of new units drive decisions on the mix of new builds and
consequently affect both energy and capacity prices. Combustion turbines have
the lowest capital and fixed O&M costs among all the new equipment options.
However, this advantage is offset by its higher variable costs associated with
higher heat rates and higher variable O&M costs. We assume the same capital
costs for new combined cycle and cogeneration units. O&M costs for new
cogeneration units are approximately 10 percent higher than those for new
combined cycle units.
Recent history has shown very rapid decreases in EPC costs, even as
performance improved (lower heat rates). Overall, we expect that the decrease in
real new plant costs will continue at a lower rate. Exhibit 5-44 summarizes our
assumptions for new power plant characteristics.
- --------------------------------------------------------------------------------
128 [LOGO] ICF CONSULTING
Exhibit 5-44
New Power Plant Characteristics
- --------------------------------------------------------------------------------
Base and High Price
Parameter Case Downside Case
- --------------------------------------------------------------------------------
New Combined Cycle Units
Levelized(1,2) Capital Cost ($/kW) 557 493
Fixed O&M ($/kW/yr) 16.0 13.0
Non-Fuel Variable O&M ($/MWh) 1.06 - 6.23 1.03 - 6.23
Levelized(1,2) Heat Rate (Btu/kWh) 6,703 6,328
Availability (%) 92% 92%
- --------------------------------------------------------------------------------
New Combustion Turbine Units
Levelized(1,2) Capital Cost ($/kW) 337 309
Fixed O&M ($/kW/yr) 9.8 7.8
Non-Fuel Variable O&M ($/MWh)(3) 0.81 - 5.91 0.81 - 5.91
Levelized(1,2) Heat Rate (Btu/kWh) 10,603 10,202
Availability (%) 92% 91%
- --------------------------------------------------------------------------------
New LM6000 Units(4)
Levelized(1,2) Capital Cost(3) ($/kW) 555 515
Fixed O&M ($/kW/yr) 9.85 9.85
Non-Fuel Variable O&M ($/MWh)(3) 0.91 0.91
Levelized(1,2) Heat Rate (Btu/kWh) 9,445 9,003
Availability(3) (%) 97% 97%
- --------------------------------------------------------------------------------
Note: All dollar values in real 1998 dollars.
1 Levelized over 2002-2020 period, however, model incorporated a declining
cost/heat rate structure.
2 Value shown representative, actual variable O&M determined by unit
dispatch.
3 Specified by PPL Global.
4 All new LM6000 units are forecast to include SCR controls as per PPL
Global.
Exhibit 5-45
New Power Plant Capital Costs at ISO Conditions (1998$/kW) - Base Case
- --------------------------------------------------------------------------------
Combustion Turbine Combined Cycle/Cogen
----------------------------------------------------------
Soft Cost Soft Cost
Year EPC Multiplier Total EPC Multiplier Total
- --------------------------------------------------------------------------------
2002 287 1.3 373 422 1.4 591
- --------------------------------------------------------------------------------
2005 287 1.3 373 422 1.4 591
- --------------------------------------------------------------------------------
2010 234 1.3 304 380 1.4 533
- --------------------------------------------------------------------------------
2015 234 1.3 304 380 1.4 533
- --------------------------------------------------------------------------------
2020 234 1.3 304 380 1.4 533
- --------------------------------------------------------------------------------
Levelized
2002 - 2020 262 1.3 340 402 1.4 563
- --------------------------------------------------------------------------------
We generally consider EPC costs to include all costs except overnight
construction costs and IDC and all other costs to be included in the soft cost
multiplier. These other costs include development costs, contingency fees,
electrical connection costs, gas connection costs, change orders, other site
modifications, financing related costs, etc.(20) We assume a lower soft cost
multiplier for combustion turbines relative to combined cycles and cogeneration
facilities, reflective of the greater potential for combustion turbine
construction at existing sites.
- ----------
20 An alternate, but consistent view would include initial spares, land, and
building/facilities costs in EPC, but IDC as part of the soft costs.
- --------------------------------------------------------------------------------
129 [LOGO] ICF CONSULTING
Although the Downside Case assumes incremental heat rate improvements, we
do not foresee major breakthroughs in new power plant technology over the
forecast horizon. In the Downside Case, we assume slightly lower capital costs
and heat rates for all new equipment (relative to the Base Case).
We assume that there is some variation in capital costs across the U.S.,
due to variation primarily in site labor and site material costs. PJM is assumed
to be on par with the US average while NEPOOL is considered to be roughly 10
percent above average.
In addition to this regional multiplier, ICF used temperature and altitude
adjustment factors in order to capture the true cost of a summer rated
incremental MW. PJM West incorporates a 1.041 percent multiplier while AZNM
incorporates a 1.202 percent multiplier, reflecting extreme differences in
weather and altitude characteristics.
Exhibit 5-46
Regional Capital Cost Multipliers for Fossil-Fuel Units
- --------------------------------------------------------------------------------
Region Multiplier(1)
- --------------------------------------------------------------------------------
PJM East 1.051
- --------------------------------------------------------------------------------
PJM West 1.041
- --------------------------------------------------------------------------------
PJM South 1.053
- --------------------------------------------------------------------------------
NEPOOL 1.037
- --------------------------------------------------------------------------------
Montana 1.172
- --------------------------------------------------------------------------------
AZNM 1.202
- --------------------------------------------------------------------------------
PacNW 1.050
- --------------------------------------------------------------------------------
1 Multipliers include adjustments for regional site costs as well as
adjustments for regional climate conditions.
The underlying assumption for Base Case capital costs embodies a decrease
of 1.0 percent from 2005 through 2010 and 1.5 percent per annum thereafter in
real terms. In our model, however, we incorporate cost improvements in discrete
steps (as opposed to a continuous distribution). As such, we generally model
capital costs in 3- to 5-year steps, although there may be some exceptions. The
specification used in the modeling is illustrated in Exhibits 5-47 through 5-50.
For example, we may treat 2002 through 2004, 2005 through 2006, 2007 through
2009, 2010 through 2014, and 2015 through 2020 as single steps.
Exhibit 5-47
Eastern Interconnect New Unit Characteristics by Vintage -
Base and High Cases (1998$/kW)
- ----------------------------------------------------------------------------------------------------------
Combined Cycles and
Cogeneration Combustion Turbines Jet Engines
Year -----------------------------------------------------------------------------------------------
PJM PJM PJM PJM PJM PJM PJM PJM PJM
East West South NEPP East West South NEPP East West South NEPP
- ----------------------------------------------------------------------------------------------------------
2001 648 642 648 706 394 390 394 429 522 517 522 569
- ----------------------------------------------------------------------------------------------------------
2003 648 642 648 706 394 390 394 429 522 517 522 569
- ----------------------------------------------------------------------------------------------------------
2005 648 642 648 706 394 390 394 429 522 517 522 569
- ----------------------------------------------------------------------------------------------------------
2010 616 610 616 671 374 371 374 408 496 492 496 541
- ----------------------------------------------------------------------------------------------------------
2015 586 580 586 638 356 353 356 388 472 467 472 514
- ----------------------------------------------------------------------------------------------------------
2020 557 552 557 607 339 335 339 369 449 445 449 489
- ----------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
130 [LOGO] ICF CONSULTING
Exhibit 5-48
Eastern Interconnect New Unit Characteristics by Vintage - Low Case (1998$/kW)
- ----------------------------------------------------------------------------------------------------------
Combined Cycles and
Cogeneration Combustion Turbines Jet Engines
Year -----------------------------------------------------------------------------------------------
PJM PJM PJM PJM PJM PJM PJM PJM PJM
East West South NEPP East West South NEPP East West South NEPP
- ----------------------------------------------------------------------------------------------------------
2001 589 583 648 641 355 351 355 387 471 467 471 514
- ----------------------------------------------------------------------------------------------------------
2003 567 562 648 618 342 338 342 372 453 449 453 494
- ----------------------------------------------------------------------------------------------------------
2005 545 540 648 594 328 324 328 357 435 430 435 474
- ----------------------------------------------------------------------------------------------------------
2010 500 495 616 545 301 299 301 329 400 397 400 436
- ----------------------------------------------------------------------------------------------------------
2015 459 454 586 500 276 274 276 301 393 389 393 428
- ----------------------------------------------------------------------------------------------------------
2020 418 415 557 456 252 249 252 274 332 329 332 361
- ----------------------------------------------------------------------------------------------------------
Exhibit 5-49
WSCC New Unit Characteristics by Vintage - Base and High Cases (1998$/kW)
- ----------------------------------------------------------------------------------------------------------
Combined Cycles and
Cogeneration Combustion Turbines Jet Engines
Year -----------------------------------------------------------------------------------------------
Montana AZNM PacNW Montana AZNM PacNW Montana AZNM PacNW
- ----------------------------------------------------------------------------------------------------------
2001 722 740 713 439 450 433 581 596 574
- ----------------------------------------------------------------------------------------------------------
2003 722 740 713 439 450 433 581 596 574
- ----------------------------------------------------------------------------------------------------------
2005 722 740 713 439 450 433 581 596 574
- ----------------------------------------------------------------------------------------------------------
2010 687 704 678 417 428 412 553 567 546
- ----------------------------------------------------------------------------------------------------------
2015 653 670 644 397 407 392 526 539 519
- ----------------------------------------------------------------------------------------------------------
2020 621 637 613 377 387 373 500 513 494
- ----------------------------------------------------------------------------------------------------------
Exhibit 5-50
New Unit Characteristics by Vintage - Low Case (1998$/kW)
- ----------------------------------------------------------------------------------------------------------
Combined Cycles and
Cogeneration Combustion Turbines Jet Engines
Year -----------------------------------------------------------------------------------------------
Montana AZNM PacNW Montana AZNM PacNW Montana AZNM PacNW
- ----------------------------------------------------------------------------------------------------------
2001 656 672 648 396 406 390 524 538 518
- ----------------------------------------------------------------------------------------------------------
2003 632 648 624 381 390 375 504 517 498
- ----------------------------------------------------------------------------------------------------------
2005 607 622 600 365 374 360 484 496 478
- ----------------------------------------------------------------------------------------------------------
2010 558 571 550 336 345 332 446 457 440
- ----------------------------------------------------------------------------------------------------------
2015 512 525 505 308 316 304 438 449 432
- ----------------------------------------------------------------------------------------------------------
2020 467 479 461 280 287 277 369 379 365
- ----------------------------------------------------------------------------------------------------------
Based on the economics of constructing new power plants, ICF has not
modeled the potential for new coal power plants to be built. That is, the
turbine derivative units are much more economical to build and operate than coal
plants. Given the high capital cost of coal units, developers would always favor
turbines or turbine derivatives over coal units unless large subsidies were
provided for coal plant construction. This is in spite of the generally lower
variable costs of operating on coal plants.
To illustrate the cost differential, typical capital costs on a coal plant
would be on the order of $1,200/kW/yr versus $600/kW/yr for a combined cycle.
Average hourly profits for a coal unit may be on the order of $1/MWh greater
than for a combined cycle such that if the plants were to dispatch an equivalent
percent of total hours - 85 percent - coal plants would receive, on average,
$7.5/kW more than a combined cycle in profit. At average energy profit levels of
$6/MWh and $5/MWh, respectively, a combined cycle would require a capital
recovery from the capacity markets at 30 to 40 percent below that required by
the coal.
- --------------------------------------------------------------------------------
131 [LOGO] ICF CONSULTING
We allow the model to optimize over the market analysis period, the
selection of new units based on the economics of these new units and the overall
system. However, we do restrict this selection in the near-term as a typical
combined cycle unit requires a lead-time of two or more years prior to coming
on-line. Given the longer lead-time required for a combined cycle versus a
combustion turbine unit, we assume that a limited number of new combined cycle
units are possible before 2001. Exhibit 5-51 shows the model restrictions placed
on unplanned builds.
Exhibit 5-51
Unplanned Build Restrictions - All Cases
- --------------------------------------------------------------------------------
Combustion Turbine Restriction
Year ------------------------------ Combined Cycle Restriction
High and Base Downside
- --------------------------------------------------------------------------------
2001 Yes Yes Yes (Only those under construction)
- --------------------------------------------------------------------------------
2002 Yes No Yes (Only those under construction)
- --------------------------------------------------------------------------------
Post 2002 No No No
- --------------------------------------------------------------------------------
Financing of New Power Plants
A major source of uncertainty with respect to new power plant
characteristics is the financing structure of merchant power plants. The Base
and High Price Cases incorporate a 50/50 debt to equity financing for new
combined cycle and cogeneration units while a 40/60 debt to equity ratio is
incorporated for new peaking units. This difference is intended to highlight the
differing risk profiles of the units. New combined cycle baseload units are
considered less risky despite higher investment costs given their competitive
position against existing units in the regional supply mixes. That is, combined
cycles are expected to earn a steady revenue stream from dispatch. In
comparison, peaking units rely on revenues from the more volatile capacity
markets and are considered a riskier investment on a stand-alone basis. The
above notwithstanding, these assumptions may be conservatively low in that
peaking units selling into the spot market (this analysis assumes spot only
sales) may have even higher financing costs than assumed here.
For peaking units, a nominal after-tax rate of return on equity of 14
percent, and a nominal interest rate on debt of 10 percent, results in a
levelized, real annual capital charge rate of between 13.7 and 14.9 percent for
the PJM and NEPOOL regions. The Arizona/New Mexico regions fall in a similar
range as NEPOOL with capital charge rates of 13.7 to 15.0. Baseload units are
somewhat lower at between 12.7 and 13.9 percent. Exhibits 5-52 and 5-53
summarize the derivation of the annual real fixed charge rate for peaking and
baseload units.
- --------------------------------------------------------------------------------
132 [LOGO] ICF CONSULTING
Exhibit 5-52
Calculation of the Annual Real Fixed Charge Rate for Peaking Units (ARFCR)
- ---------------------------------------------------------------------------------------------------------------
Parameter PJM- PJM- PJM- NEPOOL Montana AZNM
East West South
- ---------------------------------------------------------------------------------------------------------------
Input Assumptions
- ---------------------------------------------------------------------------------------------------------------
Debt Life (years) 15 15 15 15 15 15
- ---------------------------------------------------------------------------------------------------------------
Book Life (years) 30 30 30 30 30 30
- ---------------------------------------------------------------------------------------------------------------
Nominal After Tax Equity Rate (%) 14.0 14.0 14.0 14.0 14 14
- ---------------------------------------------------------------------------------------------------------------
Equity Ratio (%) 60 60 60 60 60 60
- ---------------------------------------------------------------------------------------------------------------
Nominal Debt Rate (%) 10.0 10.0 10.0 10.0 10 10
- ---------------------------------------------------------------------------------------------------------------
Debt Ratio (%) 40 40 40 40 40 40
- ---------------------------------------------------------------------------------------------------------------
Income Tax Rate (%) 41.2 41.5 40.8 40.7 39.4 40.1
- ---------------------------------------------------------------------------------------------------------------
Inflation (%) 2.5 2.5 2.5 2.5 2.5 2.5
- ---------------------------------------------------------------------------------------------------------------
Property Tax and Insurance (%) 0.8 0.7 1.5 2.0 2.3 1.9
- ---------------------------------------------------------------------------------------------------------------
Output
- ---------------------------------------------------------------------------------------------------------------
Levelized Fixed Real Capital 14.7 14.9 14.5 15.7 15.5 15.2
Charge Rate (%)
- ---------------------------------------------------------------------------------------------------------------
Real Weighted Average Cost of 8.1 8.0 8.1 8.1 8.1 8.1
Capital (%)
- ---------------------------------------------------------------------------------------------------------------
Nominal Weighted Average Cost of 10.8 10.7 10.8 10.8 10.8 10.8
Capital (%)
- ---------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
133 [LOGO] ICF CONSULTING
Exhibit 5-53
Calculation of the Annual Real Fixed Charge Rate for Baseload Units (ARFCR)
- ----------------------------------------------------------------------------------------------------------------
Parameter PJM- PJM- PJM- NEPOOL Montana AZNM
East West South
- ----------------------------------------------------------------------------------------------------------------
Input Assumptions
- ----------------------------------------------------------------------------------------------------------------
Debt Life (years) 20 20 20 20 20 20
- ----------------------------------------------------------------------------------------------------------------
Book Life (years) 30 30 30 30 30 30
- ----------------------------------------------------------------------------------------------------------------
Nominal After Tax Equity Rate (%) 14.0 14.0 14.0 14.0 14 14
- ----------------------------------------------------------------------------------------------------------------
Equity Ratio (%) 50 50 50 50 50 50
- ----------------------------------------------------------------------------------------------------------------
Nominal Debt Rate (%) 9.0 9.0 9.0 9.0 9.0 9.0
- ----------------------------------------------------------------------------------------------------------------
Debt Ratio (%) 50 50 50 50 50 50
- ----------------------------------------------------------------------------------------------------------------
Income Tax Rate (%) 41.2 41.5 40.8 40.7 39.4 40.1
- ----------------------------------------------------------------------------------------------------------------
Inflation (%) 2.5 2.5 2.5 2.5 2.5 2.5
- ----------------------------------------------------------------------------------------------------------------
Property Tax and Insurance (%) 0.8 0.7 1.5 2.0 2.3 1.9
- ----------------------------------------------------------------------------------------------------------------
Output
- ----------------------------------------------------------------------------------------------------------------
Levelized Fixed Real Capital 12.7 12.9 13.5 13.9 13.7 13.5
Charge Rate (%)
- ----------------------------------------------------------------------------------------------------------------
Real Weighted Average Cost of 7.0 7.0 7.0 7.0 7.0 7.0
Capital (%)
- ----------------------------------------------------------------------------------------------------------------
Nominal Weighted Average Cost of 9.6 9.6 9.7 9.7 9.7 9.7
Capital (%)
- ----------------------------------------------------------------------------------------------------------------
Firmly Planned Builds
In addition to the model determined builds, we incorporate a number of
announced builds explicitly in our modeling, specifically those which we
consider "firm" amongst the announced builds. The decision to include a unit as
firm is based on whether or not construction is underway.
- --------------------------------------------------------------------------------
134 [LOGO] ICF CONSULTING
Exhibit 5-54
Firm Capacity Additions in PJM as of April 2001
- ------------------------------------------------------------------------------------------------------------------------
Sub- Primary On-Line Plant
State Company Region Status Area/Plant Name Fuel Date Capacity Type
- ------------------------------------------------------------------------------------------------------------------------
NJ PSEG PJM East Operational Burlington Gas 2000 168 CT
- ------------------------------------------------------------------------------------------------------------------------
DE Motiva PJM East Operational Delaware City Refinery Coal 2000 224 Cogen
Enterprises
- ------------------------------------------------------------------------------------------------------------------------
NJ Sithe PJM East Operational Gilberton Gas 2000 100 CC
- ------------------------------------------------------------------------------------------------------------------------
PA Unknown PJM East Operational Peckville Gas 2000 60 CT
- ------------------------------------------------------------------------------------------------------------------------
PA PECO PJM East Operational Pen Argyl Methane 2000 8 Landfill
- ------------------------------------------------------------------------------------------------------------------------
VA TECO PJM East Under Accomack County Oil 2001 315 CT
Construction
- ------------------------------------------------------------------------------------------------------------------------
NJ PSEG PJM East Under Bergen County Gas 2002 500 Cogen
Construction
- ------------------------------------------------------------------------------------------------------------------------
PA Colombia PJM East Under Liberty Project Gas 2002 568 Cogen
Electric Construction
- ------------------------------------------------------------------------------------------------------------------------
NJ PGE PJM East Under Mantua Creek Gas 2002 800 CC
Construction
- ------------------------------------------------------------------------------------------------------------------------
NJ AES PJM East Under Red Oak Gas 2002 830 CC
Construction
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM East Firmly Planned Eden Gas 2002 90 CT
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM East Firmly Planned Hatfield Gas 2002 90 CT
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM East Firmly Planned Upper Hanover Gas 2003 90 CT
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM East Firmly Planned West Earl Gas 2003 450 CT
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM East Firmly Planned West Hempfield Gas 2003 180 CT
- ------------------------------------------------------------------------------------------------------------------------
NJ PSEG PJM East Under Linden Gas 2003 1,186 CC
Construction
- ------------------------------------------------------------------------------------------------------------------------
NJ Sithe PJM Operational Gilberton Gas 2000 100 CT
South
- ------------------------------------------------------------------------------------------------------------------------
PA PEI PJM West Operational Archibald Gas 2000 25 Cogen
Powercorp
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM West Firmly Planned Brunner Island Uprate Coal 2002 14 Coal
- ------------------------------------------------------------------------------------------------------------------------
PA Williams PJM West Operational Hazelton Gas 1999 250 CC
Energy
- ------------------------------------------------------------------------------------------------------------------------
PA AES Corp PJM West Under Ironwood Gas 2001 720 CC
Construction
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM West Firmly Planned Lower Mount Bethel Gas 2002 520 CC
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM West Firmly Planned Lower Mount Bethel Duct Gas 2002 82 CC
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM West Firmly Planned Montour Uprate Coal 2001 28 Coal
- ------------------------------------------------------------------------------------------------------------------------
PA PECO PJM West Under Muddy Run Upgrade Water 2001 104 Pump
Construction Storage
- ------------------------------------------------------------------------------------------------------------------------
PA Reliant PJM West Proposed Portland Gas 2002 472 CC
- ------------------------------------------------------------------------------------------------------------------------
PA American PJM West Under Somerset Wind Project Wind 2000 10 Wind
National Construction
Wind
- ------------------------------------------------------------------------------------------------------------------------
PA PPL PJM West Firmly Planned Susquehanna Nuclear 2003 102 Nuclear
- ------------------------------------------------------------------------------------------------------------------------
Total PJM Builds 8,086
- ------------------------------------------------------------------------------------------------------------------------
Total PJM East Builds 5,659
- ------------------------------------------------------------------------------------------------------------------------
Total PJM South Builds 100
- ------------------------------------------------------------------------------------------------------------------------
Total PJM West Builds 2,327
- ------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
135 [LOGO] ICF CONSULTING
Within PJM, there are a significant number of announced capacity additions
or expansion. However, less than half of the total announced capacity is
considered to be firm by 2003. Note that as additional capacity requirements
beyond the firm units occur, the IPM(TM) model will add the optimal capacity
type and amount.
Exhibit 5-55
Firm Capacity Additions in NEPOOL as of April 2001
- ---------------------------------------------------------------------------------------------------------------
On-
Sub- Primary Line
State Company Region Status Area/Plant Name Fuel Date Capacity Plant Type
- ---------------------------------------------------------------------------------------------------------------
MA Energy NEPOOL Operational Dighton Project Gas 1999 185 CC
Management,
Inc.
- ---------------------------------------------------------------------------------------------------------------
ME Indeck Energy NEPOOL Operational Jonesboro Project Renewable 1999 24 Renewables
Services
- ---------------------------------------------------------------------------------------------------------------
ME Indeck Energy NEPOOL Operational West Enfield Renewable 1999 24 Renewables
Services Project
- ---------------------------------------------------------------------------------------------------------------
MA El Paso Energy NEPOOL Operational Agawam Project Gas 2000 276 CC
Marketing
Company
- ---------------------------------------------------------------------------------------------------------------
ME SkyGen NEPOOL Operational Androscoggin Gas 2000 157 Cogen - CC
- ---------------------------------------------------------------------------------------------------------------
MA American NEPOOL Operational Blackstone Project Gas 2000 589 CC
National Power
- ---------------------------------------------------------------------------------------------------------------
CT Duke Power NEPOOL Operational Bridgeport Project Gas 2000 520 CC
- ---------------------------------------------------------------------------------------------------------------
ME Duke Energy NEPOOL Operational Maine Gas 2000 520 CC
Independence
Station Project
- ---------------------------------------------------------------------------------------------------------------
CT Power NEPOOL Operational Milford Gas 2000 544 CC
Development
Corporation
- ---------------------------------------------------------------------------------------------------------------
MA U.S. Generating NEPOOL Operational Millennium Power Gas 2000 400 CC
Company Project
- ---------------------------------------------------------------------------------------------------------------
ME Energy NEPOOL Operational Rumford Gas 2000 265 CC
Management Inc.
- ---------------------------------------------------------------------------------------------------------------
RI Energy NEPOOL Operational Tiverton Project Gas 2000 265 CC
Management Inc.
- ---------------------------------------------------------------------------------------------------------------
ME Preti, Flaherti, NEPOOL Operational Bucksport Gas 2001 174 CC
Beliveu &
Pachios LLC
- ---------------------------------------------------------------------------------------------------------------
CT PPL NEPOOL Operational Wallingford Gas 2001 220 CT
- ---------------------------------------------------------------------------------------------------------------
ME Calpine NEPOOL Operational Westbrook Gas 2001 540 CC
Corporation
- ---------------------------------------------------------------------------------------------------------------
MA American NEPOOL Under ANP Bellingham Gas 2002 580 CC
National Power Construction
- ---------------------------------------------------------------------------------------------------------------
MA Southern Energy NEPOOL Under Kendall Power Gas 2002 263 CC
Construction Project
- ---------------------------------------------------------------------------------------------------------------
CT Lake Road NEPOOL Under Lake Road Gas 2002 792 CC
Generation LP Construction
- ---------------------------------------------------------------------------------------------------------------
MA Sithe Energies NEPOOL Under Mystic Gas 2002 800 CC
Construction
- ---------------------------------------------------------------------------------------------------------------
Total NEPOOL Builds 7,138
- ---------------------------------------------------------------------------------------------------------------
As in PJM, only a portion of the announced builds in NEPOOL are expected
to be on line by 2002. In total, we include 7.1 GW of new capacity as firm in
the modeling. Additional announced capacity is shown in Exhibit 5-54 and 5-55
- --------------------------------------------------------------------------------
136 [LOGO] ICF CONSULTING
As mentioned above, in addition to the firm capacity expected to come
on-line in the next several years, NEPOOL has a large amount of announced
capacity additions. Including both firm and announced additions, a total of
roughly 35GW of capacity are in planning stages. Of this pool of announced
capacity, only 20 percent or roughly 7.1 GW, is expected to come on-line as
planned.
Exhibit 5-56
AZNM Firm Capacity Additions as of April 2001
- --------------------------------------------------------------------------------------------------------------
On-
Sub- Area/Plant Primary Line
State Company Region Status Name Fuel Date Capacity Plant Type
- --------------------------------------------------------------------------------------------------------------
AZ PPL Arizona Under Sundance Gas 2002 440 Combustion
Construction Turbine
- --------------------------------------------------------------------------------------------------------------
AZ Calpine & Arizona Under West Gas 2001 630 Combined
Pinnacle Construction Phoenix Cycle
West Power
Station
- --------------------------------------------------------------------------------------------------------------
AZ Calpine Arizona Under South Point Gas 2001 500 Combined
Energy Construction Power Plant Cycle
- --------------------------------------------------------------------------------------------------------------
AZ Calpine Arizona Under Mohave Gas 1999 76 Combustion
Construction Turbine
- --------------------------------------------------------------------------------------------------------------
AZ Pinnacle Arizona Under Redhawk Gas 2001 2120 Combined
Energy Construction Cycle
West
- --------------------------------------------------------------------------------------------------------------
AZ Calpine & Arizona Under West Gas 2001 630 Combined
Pinnacle Construction Phoenix Cycle
West Power
Station
- --------------------------------------------------------------------------------------------------------------
AZ Duke Arizona Under Arlington Gas 2002 550 Combined
Energy Construction Valley Cycle
- --------------------------------------------------------------------------------------------------------------
AZ PG&E Arizona Under Harquahala Gas 2003 1040 Combined
Construction Generating Cycle
Project
- --------------------------------------------------------------------------------------------------------------
AZ PPL Arizona Under Griffith Gas 2001 120 Combined
Construction Energy Cycle
Project
(Duct Firing
Component)
- --------------------------------------------------------------------------------------------------------------
AZ PPL Arizona Under Griffith Gas 2001 420 Combined
Construction Energy Cycle
Project
- --------------------------------------------------------------------------------------------------------------
AZ PPL Arizona Under Coolidge Gas 2002 270 Combustion
Construction (Southeast Turbine
of Phoenix)
- --------------------------------------------------------------------------------------------------------------
AZ Reliant Arizona Under Desert Gas 2001 500 Combined
Energy Construction Basin Cycle
- --------------------------------------------------------------------------------------------------------------
2001 Firm 4,996
2002 Firm 1,260
Total Firm Capacity 7,296
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
137 [LOGO] ICF CONSULTING
Exhibit 5-57
PacNW Firm Capacity Additions as of April 2001
- ---------------------------------------------------------------------------------------------------------------
On-
Sub- Area/Plant Primary Line Plant
State Company Region Status Name Fuel Date Capacity Type
- ---------------------------------------------------------------------------------------------------------------
ID Cogentrix Pacific Under Rathdrum Gas 2001 270 Combined
Energy Northwest Construction Power Cycle
Project
- ---------------------------------------------------------------------------------------------------------------
WA PPL Pacific Under Starbuck Gas 2004 1200 Combined
Northwest Construction Cycle
- ---------------------------------------------------------------------------------------------------------------
WA Florida Pacific Under Everett Gas 2001 248 Combined
Power & Northwest Construction Project Cycle
Light Co
- ---------------------------------------------------------------------------------------------------------------
WA Puget Pacific Under Frederickson Gas 2002 249 Combined
Sound Northwest Construction - Tenaska Cycle
Power & WA Partners
Light II
Co_WA
- ---------------------------------------------------------------------------------------------------------------
OR Avista Pacific Under Coyote Gas 2002 280 Combined
Power Northwest Construction Springs Unit Cycle
2
- ---------------------------------------------------------------------------------------------------------------
OR Calpine Pacific Under Hermiston Gas 2002 484 Cogen -
Northwest Construction Power CC
Project
- ---------------------------------------------------------------------------------------------------------------
OR PacifiCorp Pacific Under Klamath Gas 2001 500 Cogen -
Northwest Construction Falls Project CC
- ---------------------------------------------------------------------------------------------------------------
2001 Firm 1,018
2002 Firm 1,013
Total Firm Capacity 3,231
- ---------------------------------------------------------------------------------------------------------------
Exhibit 5-58
LILCO Firm Capacity Additions as of April 2001
- ---------------------------------------------------------------------------------------------------------------
On-
Sub- Area/Plant Primary Line Plant
State Company Region Status Name Fuel Date Capacity Type
- ---------------------------------------------------------------------------------------------------------------
NY PPL LILCO Under Kings Park Gas 2003 270 Combustion
Construction (Long Turbine
Island):
Generator
- ---------------------------------------------------------------------------------------------------------------
Total Firm Capacity 270
- ---------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
138 [LOGO] ICF CONSULTING
Exhibit 5-59
ComEd Firm Capacity Additions as of April 2001
- ---------------------------------------------------------------------------------------------------------------
On-
Sub- Area/Plant Primary Line
State Company Region Status Name Fuel Date CAPACITY Plant Type
- ---------------------------------------------------------------------------------------------------------------
IL Enron ComEd Under Wilton Gas 2000 650 Combustion
Construction Center Turbine
- ---------------------------------------------------------------------------------------------------------------
IL People ComEd Under Elwood Gas 1999 600 Combustion
Energy Construction Turbine
- ---------------------------------------------------------------------------------------------------------------
IL LS Power ComEd Under Kendall Gas 2002 1160 Combined
(Aquilla Construction County Cycle
Energy)
- ---------------------------------------------------------------------------------------------------------------
IL Indeck ComEd Under Sabrooke Gas 2000 300 Combined
Energy Construction Indeck Cycle
Services
- ---------------------------------------------------------------------------------------------------------------
IL PPL ComEd Under Marengo Gas 2003 270 Combustion
Construction (McHenry Turbine
County)
- ---------------------------------------------------------------------------------------------------------------
IL PPL ComEd Under University Gas 2002 540 Combustion
Construction Park (Will Turbine
County)
- ---------------------------------------------------------------------------------------------------------------
IL Duke Energy ComEd Under Duke Lee Gas 2001 640 Combustion
Construction IL Turbine
- ---------------------------------------------------------------------------------------------------------------
IL Enron ComEd Under Lincoln Gas 2000 668 Combustion
Construction Energy Turbine
Center
- ---------------------------------------------------------------------------------------------------------------
IL Pennsylvania ComEd Under La Salle Uranium 2001 106 Nuclear
Electric Co Construction
- ---------------------------------------------------------------------------------------------------------------
2001 Firm 2,964
2002 Firm 1,700
Total Firm Capacity 4,934
- ---------------------------------------------------------------------------------------------------------------
Nuclear Performance and Retirements
Annual nuclear capacity factors tend to vary substantially from year to
year. While part of this variability results from the scheduling of downtime for
refueling and scheduled maintenance, which does not tend to follow an annual
cycle, there is nonetheless an underlying element of unpredictability, even in
the short term. A large part of this unpredictability results from the
relatively long down-time required for unscheduled maintenance, either to
prevent developing problems or to respond to Nuclear Regulatory Commission (NRC)
requirements. While economic incentives may increasingly make it desirable for
utilities to employ preventative maintenance to avoid forced outages, some
degree of unpredictability will almost certainly remain.
Generally, we model nuclear plants as retiring at the end of their
operating license. However, certain plants retire prior to the termination of
their license for poor performance or safety reasons. In particular, while fuel
costs are low, O&M and capital improvements can be high. We do not assume
additional retirements, though we assume that no licenses may be extended in the
Base Case.
- --------------------------------------------------------------------------------
139 [LOGO] ICF CONSULTING
Exhibit 5-60
PJM and NEPOOL Nuclear Unit Retirement Plans
- -----------------------------------------------------------------------------------------------
Unit Region Capacity (MW) Retirement Year
- -----------------------------------------------------------------------------------------------
Oyster Creek 1 PJM East 619 2010
- -----------------------------------------------------------------------------------------------
Salem 1 PJM East 1,106 2016
- -----------------------------------------------------------------------------------------------
Salem 2 PJM East 1,106 2021
- -----------------------------------------------------------------------------------------------
Hope Creek 1 PJM East 1,031 2026
- -----------------------------------------------------------------------------------------------
Limerick 1 PJM East 1,105 2024
- -----------------------------------------------------------------------------------------------
Limerick 2 PJM East 1,115 2029
- -----------------------------------------------------------------------------------------------
Peach Bottom 2 PJM West 1,093 2033 (20 year
extension)
- -----------------------------------------------------------------------------------------------
Peach Bottom 3 PJM West 1,093 2034 (20 year
extension)
- -----------------------------------------------------------------------------------------------
Three Mile Island PJM West 786 2014
- -----------------------------------------------------------------------------------------------
Susquehanna 1 PJM West 1,090 2022
- -----------------------------------------------------------------------------------------------
Susquehanna 2 PJM West 1,094 2024
- -----------------------------------------------------------------------------------------------
Calvert Cliffs 1 PJM South 835 2034 (20 year
extension)
- -----------------------------------------------------------------------------------------------
Calvert Cliffs 2 PJM South 840 2036 (20 year
extension)
- -----------------------------------------------------------------------------------------------
Millstone 2 NEPOOL 873 2015
- -----------------------------------------------------------------------------------------------
Millstone 3 NEPOOL 1,120 2026
- -----------------------------------------------------------------------------------------------
Pilgrim NEPOOL 669 2012
- -----------------------------------------------------------------------------------------------
Sea Brook NEPOOL 1,155 2030
- -----------------------------------------------------------------------------------------------
Vermont Yankee NEPOOL 496 2012
- -----------------------------------------------------------------------------------------------
Palo Verde 1 AZNM 1,227 2025
- -----------------------------------------------------------------------------------------------
Palo Verde 2 AZNM 1,227 2026
- -----------------------------------------------------------------------------------------------
Palo Verde 3 AZNM 1,230 2027
- -----------------------------------------------------------------------------------------------
All nuclear units are considered to retire with the end of their operating
licenses. In PJM, the Peach Bottom and Calvert Cliffs units have received
20-year license extensions and are modeled as such. Units are allowed to retire
economically prior to the formal retirement. In the short-run, unexpected early
retirements could lead to high prices, but in the long-run, they could decrease
prices. This is because combined cycle units with higher availabilities increase
the total amount of low-cost infra-marginal supply resulting in overall lower
market prices.
PJM's nuclear performance (with the exception of Salem 1 and 2) has been
very strong during the 1990s, although it was weaker in the mid-1980s. We
project that the nuclear performance will continue at relatively high levels.
NEPOOL's operating nuclear plants have also performed well in the recent
past. The retirement of several units has resulted great interest in maintaining
positive performance to the existing units. We project that future availability
will increase above historical levels at these units.
Within PJM and NEPOOL, as well as in the rest of the US, deregulation
increases the incentive to maintain high availabilities, particularly given
asset sales and the high level of competition. This supports the view that
nuclear units will maintain high efficiency in the future.
Of the regions evaluated in the WSCC, only Arizona/New Mexico relies on
nuclear capacity. Historically, the Palo Verde unit has operated very well and
provides a large amount of energy to the region.
- --------------------------------------------------------------------------------
140 [LOGO] ICF CONSULTING
Exhibit 5-61
Nuclear Capacity Factor Projections (%)
- --------------------------------------------------------------------------------
Region Annual Capacity Factor Projection (%)
- --------------------------------------------------------------------------------
PJM East(1) 68.9
- --------------------------------------------------------------------------------
PJM West 85.0
- --------------------------------------------------------------------------------
PJM South 82.3
- --------------------------------------------------------------------------------
NEPOOL 67.3
- --------------------------------------------------------------------------------
Montana N/A
- --------------------------------------------------------------------------------
AZNM 80.5
- --------------------------------------------------------------------------------
1 For PJM East we do not take into account capacity factor for Salem for years
in which it had outage for a period greater than 6 months. However, Salem's
historical operation is still below 50 percent capacity factor. Excluding Salem,
PJM East would have a projected capacity factor of roughly 77 percent.
Source: Figures are based on the average of capacity factors for the years
1991-1998 as quoted by NRC.
General Unit Characteristics
Coal and oil/gas steam units are expected to attain average annual
availabilities of between 80 percent and 88 percent. As shown in Exhibit 5-62
scrubbed coal units cost $1.00/MWh more to operate than unscrubbed units and
approximately $3.00 more than oil- and gas-fired units when cycling. Oil/gas
steam units used for peak cycling incur an additional cost associated with quick
start-up. Cycling costs are only significant in the cases in which there are
thermal stresses and fatigue and thermal creep. This is primarily a problem for
steam units, and we have captured this for the steam units most likely to cycle
- - i.e., oil/gas steam units.
- --------------------------------------------------------------------------------
141 [LOGO] ICF CONSULTING
Exhibit 5-62
Existing Unit Variable O&M and Turndown Assumptions
- -------------------------------------------------------------------------------
Unit Type Variable Minimum Availability
O&M(1) Turndown
(1998$/MWh) (%) (%)
- -------------------------------------------------------------------------------
Coal
- -------------------------------------------------------------------------------
Scrubbed 2.1-12.2 40 - 60 85 - 87
- -------------------------------------------------------------------------------
Unscrubbed 1.0-11.3 25 - 61 87 - 88
- -------------------------------------------------------------------------------
Oil/Gas Steam(2) 1.3-9.4 22 - 25 80 - 86
- -------------------------------------------------------------------------------
Combined Cycles 1.03-6.23 0 91.9 - 92.4
- -------------------------------------------------------------------------------
Combustion Turbines 0.81-5.91 0 87 - 94
- -------------------------------------------------------------------------------
Nuclear 1.0 0 67 - 85
- -------------------------------------------------------------------------------
Hydro 0.0 Varies 67 - 93
- -------------------------------------------------------------------------------
Pumped Storage 0.0 0 94 - 95
- -------------------------------------------------------------------------------
1 Variable O&M shown is approximate actual O&M levels are a result of the
modeling exercised based on the optimized plant dispatch.
2 Including startup/cycling costs for oil/gas steam units. Source: ICF
Consulting, 1997 NERC GADS database.
NUG and Cogeneration Units
Exhibit 5-63
Existing NUG Capacity - NEPOOL, LILCO, AZNM, PACNW, Montana
- --------------------------------------------------------------------------------------------------
NEPOOL LILCO AZNM PACNW Montana TOTAL
- --------------------------------------------------------------------------------------------------
NUG Capacity (MW)
Gas-Fired 1,969 159 82 671 0 2,881
Coal-Fired 198 0 0 0 0 198
OTher 671 150 3 555 43 1,422
Total 2,838 309 85 1,226 43 4,501
- --------------------------------------------------------------------------------------------------
Dispatchable NUG
Capacity (MW)
2001 -- 2020 2,167 159 85 671 0 3,082
- --------------------------------------------------------------------------------------------------
Average Heat Rate of
Dispatchable NUGs
in 2001 7,020 5,077 6,334 7,700 N/A 6,533
- --------------------------------------------------------------------------------------------------
Source: ICF Consulting.
- --------------------------------------------------------------------------------
142 [LOGO] ICF CONSULTING
Exhibit 5-64
Existing NUG Capacity - PJM
- ----------------------------------------------------------------------------------------
PJM West PJM East PJM South TOTAL
- ----------------------------------------------------------------------------------------
NUG Capacity (MW)
Gas-Fired 341 2,188 116 2,645
Coal-Fired 337 341 67 745
Other 731 741 146 1,618
Total 1,409 3,270 329 5,008
- ----------------------------------------------------------------------------------------
Dispatchable NUG Capacity (MW)
1998 -- 2000 364 695 53 1,112
2005 1,093 2,374 243 3,716
2010 1,458 3,213 337 5,008
- ----------------------------------------------------------------------------------------
Average Heat Rate of Dispatchable
NUGs in 2001 (Btu/kWh) 6,200 6,700 5,600 6,500
- ----------------------------------------------------------------------------------------
Source: ICF Consulting.
PJM has a relatively large contribution from traditional NUG sources.
Approximately 7 percent of the generating capability in PJM is NUG capacity,
most is located in PJM East. Much of the capacity is currently under fixed
contracts and considered non-dispatchable. Over time, we estimate that most of
these units will become dispatchable as their contracts expire or change. Of the
regions analyzed, PJM has the most significant NUG contracts. NEPOOL and the
state of New York also have significant non-utility capacity, the bulk of which
is dispatchable. Although New York has had significant use of NUG contracts,
most were in Upstate New York, LILCO has a very limited amount of NUGs. In the
West, only limited amounts of traditional non-utility generators are operating
in the regions analyzed.
Transmission With Neighboring Regions
Note that nearly all of the U.S. and Canada's population is served by one
of the continent's four interconnected grids. In these grids, all generators are
approximately synchronized together. Also, in these grids generators are
connected via high voltage transmission systems. Power flows between these large
grids are expensive relative to intra-grid flows, and the capacity for such
transfers is limited. The four grids are as follows:
o The Eastern Interconnect -- This is the largest of the four, in
terms of both geographic area and capacity, and extends from eastern
New Mexico to Florida, Saskatchewan Canada, and eastern Canada. PJM
and NEPOOL are part of this system.
o The Western Interconnect -- This is the second largest grid and
covers the western contiguous U.S. and much of western Canada. This
grid is also called the Western System Coordinating Council or WSCC
grid. Montana and Arizona/New Mexico are part of this system.
o ERCOT -- Covering most of Texas, ERCOT is separate for primarily
political reasons, This marketplace is not analyzed in this study.
o Hydro Quebec -- This region is also separate for primarily political
reasons. Note, there is a large DC line of about 1,800 MW linking
Hydro Quebec to NEPOOL. We model Hydro Quebec as a source of
electrical energy and not as a source of firm megawatts. To the
extent Hydro Quebec can offer firm unit contingent
- --------------------------------------------------------------------------------
143 [LOGO] ICF CONSULTING
megawatts, ICF's results for capacity prices in the 2002 to 2005 period might be
substantially lower. In the pre-deregulation period, Hydro Quebec offered energy
minimums with the right to interrupt. They may not be able to offer first call
on their megawatts to non-Hydro Quebec customers. Thus, the details of future
supply will be important to resolving this uncertainty. Another reason for our
assumption that Hydro Quebec firm megawatts will not be available is that Hydro
Quebec is a large player which may act to aviod depressing prices.
Exhibit 5-65
Interconnected Grids in the U.S. and Canada
[MAP]
- --------------------------------------------------------------------------------
144 [LOGO] ICF CONSULTING
Exhibit 5-66
Eastern Interconnect Transmission Capabilities
[MAP]
In our analysis, we assume no major large new inter-regional or
inter-sub-regional lines are added. Reflecting the high costs of power lines
relative to natural gas pipelines, increasing construction of new gas power
plants decreasing price differentials between regions and decreasing economic
incentives for lines, inability of thyristor and other technologies to
inexpensively upgrade lines beyond approximately 10 percent of current
capability.
Recently, the PJM West ISO was announced. This ISO represents the border
territory between the existing PJM ISO and the likely Midwest ISO. Although
details of the PJM West ISO are not fully available, it is likely that Allegheny
Energy and Duequesne will be in PJM ISO rather than the Midwest ISO which
contains many other operations in the ECAR reliability region.
- --------------------------------------------------------------------------------
145 [LOGO] ICF CONSULTING
Exhibit 5-67
WSCC Inter-Regional Total Transfer Capability (MW)
[MAP]
The WSCC is overall a very well interconnected system with significant
transmission capability across regions.
Transmission Pricing
There are three types of inter-regional transmission charges: (i) losses
which are a minimum and unavoidable cost(21); (ii) congestion derived locational
price differences; and (iii) transmission tariffs which act as a floor propping
up prices above a competitive outcome (a competitive outcome would include the
first two charges only.)
We typically add the first two charges, the competitive charges, to
within-ISO or intra-regional movements, and the last charge is used as a floor
for inter-regional movements. In our model, the transmission tariffs for peak
and off-peak have been discounted from announced tariffs. ICF assumes there is a
single market for transmission and that the inter-regional transmission tariffs
are equal to the price differential between regions.
Note, although this study focuses on units in the PJM and NEPOOL regions,
it is necessary to model a much larger area to capture the impact of
transmission flows. As such, we have modeled the Midwest, Northeast and much of
the Southeast. The following discussion presents the assumptions used for this
broader area.
- ----------
21 These range between 1 and 6 percent in sub-regions within the Eastern
Interconnect; ICF conservatively assumes a simple rule of 1 percent loss
per 100 miles to supplement available data.
- --------------------------------------------------------------------------------
146 [LOGO] ICF CONSULTING
Exhibit 5-68
Transmission Charges Across Areas and ISOs in the Eastern Interconnect - ICF
Estimate
- --------------------------------------------------------------------------------
Transmission Charge
Regional Transmission (1998$/MWh) Line Losses (%)
- --------------------------------------------------------------------------------
Inter-Regional
- --------------------------------------------------------------------------------
PJM West to Upstate New 4.5 Peak 2.0
York 3.9 Off-Peak
- --------------------------------------------------------------------------------
Upstate New York to PJM 5.1 2.0
West (Homer City)
- --------------------------------------------------------------------------------
PJM West to ECAR 3.9 Peak 3.0
2.0 Off-Peak
- --------------------------------------------------------------------------------
PJM South to VACAR(1) 2.9 Peak 1.0
1.4 Off-Peak
- --------------------------------------------------------------------------------
Into SERC Regions(4) 2.42 Peak
1.47 Off-Peak
- --------------------------------------------------------------------------------
Intra-Regional
- --------------------------------------------------------------------------------
PJM West to PJM East(2) 0.0 3% Peak
2% Off-Peak
- --------------------------------------------------------------------------------
PJM West to PJM South(2) 0.0 3% Peak
2% Off-Peak
- --------------------------------------------------------------------------------
1 Charges into VACAR is the average of charges into the sub-regions of VACAR
- Duke, Carolina Power & Light, SCEG, and VIEPCO.
2 Limits shown are multi-directional.
3 For all other inter-regional exchanges, e.g., Into Florida, we utilize a
rate of $2.0 MWh during peak and $1.0 MWh during off-peak.
4 ICF estimates based on average of current individual utilities charges
specified in OASIS.
Sources: PJM Power Pool, NEPOOL ISO; phone conversations with power purchasers,
sellers and transmission system operators.
- --------------------------------------------------------------------------------
147 [LOGO] ICF CONSULTING
Exhibit 5-69
Transmission Charges Across Areas and ISOs in the WSCC -- ICF Estimate
- --------------------------------------------------------------------------------
From To Peak Price Line Losses (%)
($98/MWh)
- --------------------------------------------------------------------------------
Montana NWPPE 5.10 peak 5
2.60 off-peak
- --------------------------------------------------------------------------------
NWPPE Montana 4.90 peak 5
2.50 off-peak
- --------------------------------------------------------------------------------
RMP Montana 4.90 peak 5
2.50 off-peak
- --------------------------------------------------------------------------------
Montana RMP 3.30 peak 5
1.70 off-peak
- --------------------------------------------------------------------------------
Alberta BC 4.20 peak 15
2.10 off-peak
- --------------------------------------------------------------------------------
BC Alberta 1.40 peak None
0.70 off-peak
- --------------------------------------------------------------------------------
BC PACNW 3.20 peak 7
1.60 off-peak
- --------------------------------------------------------------------------------
PACNW BC 1.40 peak 7
0.70 off-peak
- --------------------------------------------------------------------------------
1 ICF estimate of transmission charges into each of the regions derived
based on average of current individual utility charges as specified in
OASIS.
2 After 2005, these regions transmission charges change due to ICF ISO
assumptions.
Exhibit 5-70
Transmission Charges Across ISOs -- ICF Estimate
- --------------------------------------------------------------------------------
ISO Region Peak ($/MWh) Off Peak ($/MWh)
- --------------------------------------------------------------------------------
Into MAIN 2.7 1.8
- --------------------------------------------------------------------------------
Into ECAR 3.4 1.2
- --------------------------------------------------------------------------------
Into MAPP 2.6 1.5
- --------------------------------------------------------------------------------
Into SPP 3.6 1.8
- --------------------------------------------------------------------------------
Into California 3.2 2.1
- --------------------------------------------------------------------------------
Into NWP 3.1 2.2
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
148 [LOGO] ICF CONSULTING
Exhibit 5-71
Envisioned ISO Regions - ICF View of U.S. Eastern Interconnect
- --------------------------------------------------------------------------------
1998 - 2005 2006 - 2020
- --------------------------------------------------------------------------------
MAIN Midwest/Alliance
- -------------------------------- (MAIN & ECAR)
ECAR
- --------------------------------------------------------------------------------
MAPP MAPP
- --------------------------------------------------------------------------------
SPP SPP
- --------------------------------------------------------------------------------
Entergy
- --------------------------------
Southern Company SERC
- -------------------------------- (Southern Company, TVA, and Entergy)
TVA
- --------------------------------------------------------------------------------
VACAR VACAR
- --------------------------------------------------------------------------------
Florida Florida
- --------------------------------------------------------------------------------
Northern California
- -------------------------------- California
Southern California
- --------------------------------------------------------------------------------
Arizona/New Mexico Arizona/New Mexico
- --------------------------------------------------------------------------------
Rockies Rockies
- --------------------------------------------------------------------------------
PACNW
- --------------------------------
NWPPE NWPP
- -------------------------------- (Northwest Power Pool)
Montana
- --------------------------------------------------------------------------------
We are anticipating that the currently recognized NERC sub-regions and
other sub-regional breakouts used by ICF will be transformed into more
aggregated regional ISOs. In the longer term, i.e., starting between 2003 and
2005, we expect larger ISO groupings. We believe this is an intermediate
scenario between the extremes of having a single Eastern Interconnect ISO and a
continuation of the current fragmented structure. The consequence is a reduction
in the number of fixed tariffs in the model. A more disaggregated structure
would result in more tariffs and potentially higher regional prices.
At this time, in spite of some recent progress, the Midwest is one of the
least organized in terms of establishing ISO boundaries, determining tariffs,
and implementing explicit rules related to reserves, trading of products, etc.
Specifically, the Midwest lags behind California, PJM, and NEPOOL. Other ISO
markets have more recently been announced. Allegheny Energy has broken from the
Midwest ISO and intends to join the newly announced PJM West ISO. SPP and
Entergy have submitted plans for a separate TRANSCO organization. The Alliance
RTO is planned for Virginia and extends to the Midwest. Additionally, the
non-Virginia sub-regions of VACAR have announced plans for a separate ISO called
GRID South.
- --------------------------------------------------------------------------------
149 [LOGO] ICF CONSULTING
In the WSCC, it is also assumed that transmission pancaking will become
very limited in the mid-term forecast horizon. ICF projects that the WSCC will
consist of approximately four transmission ISOs. The largest will encompass the
Pacific Northwest, Montana, and the Eastern Northwest Power Pool in a single
ISO.
In addition to the general regional modeling assumptions, specific unit
level detail for the PPL assets have been modeled here and are described in
Chapter Six.
- --------------------------------------------------------------------------------
150 [LOGO] ICF CONSULTING
CHAPTER SIX
PPL UNIT LEVEL ASSUMPTIONS AND RESULTS
- --------------------------------------------------------------------------------
Introduction
PPL owns and operates electrical generating facilities in several power
markets across the United States. In addition to the broad geographic locations,
the PPL units have a broad configuration ranging from baseload hydro and coal
units to units generally geared toward the peaking markets. As such, their
interests are broad and diversified. PPL is also supplementing their existing
capacity with new mid-level units in several marketplaces. The main focus of
this report is the outlook and forward operational considerations for the
existing PPL facilities. In addition, the planned facilities are also reviewed.
This chapter outlines the PPL generating capacity as well as the assumptions
incorporated in ICF modeling of these units.
Exhibit 6-1
PPL Generating Stations Regional Diversification
[MAP]
Given the diversity of the portfolio, both from the geographical
perspective and the unit type perspective, we have organized this chapter to
provide descriptions of the fleet from both orientations.
- --------------------------------------------------------------------------------
151 [LOGO] ICF CONSULTING
Summary of Generation Assets by Region
Exhibit 6-2
Summary of PPL Asset Characteristics by Region
- ------------------------------------------------------------------------------------------
Mon-
Parameter PJM NEPOOL tana AZ/NM PacNW LILCO ComEd TOTAL
- ------------------------------------------------------------------------------------------
Number of 54 41 39 3 1 1 1 140
Generators(1)
- ------------------------------------------------------------------------------------------
Total Capacity(2) 1,048 323 1,242 710 1,200 270 540 13,334
- ------------------------------------------------------------------------------------------
Average Heat 9,255 5,961 9,000 7,120 6,753 9,600 9,600 8,926
Rate(3)(Btu/kWh)
- ------------------------------------------------------------------------------------------
Average Fuel 9.7 19.1 5.5 19.2 19.2 30.4 27.3 10.2
Costs(4) ($/MWh)
- ------------------------------------------------------------------------------------------
NPV of Dispatch 7,950 272 2,108 471 563 128 263 11,755
Revenues ($000)(5)
- ------------------------------------------------------------------------------------------
NPV of Dispatch
Revenues 879 842 1,696 663 469 476 487 882
(1998$/kW)(5)
- ------------------------------------------------------------------------------------------
Note: Includes existing units and any firmly planned capacity additions. Values
calculated for PPL owned portions only.
1 Number of physical generating units at the PPL assets analyzed herein. PPL
owns additional peaking capacity in PJM.
2 PPL owned portion of 2005 capacity. Includes planned capacity uprates.
3 Weighted by generation for 2005. HHV. Full Load.
4 Represents projections for 2005, weighted by generation.
5 NPV is calculated using an 11.2 percent real discount rate. Does not
include taxes, debt or some cost items such as new capital additions.
Includes revenue, short-run variable costs and estimated non-fuel O&M.
The core of the PPL asset base is concentrated in PJM, particularly in the
western sub-region. Recent acquisitions of Montana Power and Bangor Hydro assets
have given PPL a sizable presence in the Montana and NEPOOL markets as well. In
addition, PPL has begun development of new projects in NEPOOL, the PJM Eastern
sub-region, LILCO, ComEd, Arizona-New Mexico, and PacNW. The portfolio of power
plants is very well diversified and includes primarily hydro and coal units in
Montana and PJM, hydro units in NEPOOL, and new turbine-fired baseload and
peaking units in PJM, NEPOOL, Arizona, and PacNW.
- --------------------------------------------------------------------------------
152 [LOGO] ICF CONSULTING
Exhibit 6-3
PPL PJM Generating Stations
[MAP]
The majority of the assets are located in PJM, PPL's original operating
region. The PPL units are predominately located to the west of the major points
of congestion within PJM. However, PPL has a presence in both western and
eastern PJM.
- --------------------------------------------------------------------------------
153 [LOGO] ICF CONSULTING
Exhibit 6-4
Summary of PPL Asset Characteristics within PJM
- ---------------------------------------------------------------------------------------------------------------------------------
Capa Heat On- Fuel Annual Minimum Avail- SO(2)/NO(x)
Modeled Unit Included Units city Rate Line Type Fixed O&M Turndown ability Rate (lbs/
(MW) (BTU/ Year (98$/ (%) (%) MMBtu)
kWh) kW)
- ---------------------------------------------------------------------------------------------------------------------------------
Combined Cycle Units
- ---------------------------------------------------------------------------------------------------------------------------------
Mount Bethel 520 6,928 2002 Gas 16.0 -- 92 0/0.02
--------------------------------------------------------------------------------------------------------------
Mount Bethel Mount Bethel 82 9,675 2002 Gas 9.8 -- 92 0/0.1
Duct
- ---------------------------------------------------------------------------------------------------------------------------------
Coal Units
- ---------------------------------------------------------------------------------------------------------------------------------
Brunner Island Brunner Island 699 9,179 1961 Coal 16.8 43 84 2.8/0.31
1&2
- ---------------------------------------------------------------------------------------------------------------------------------
Brunner Island 735 9,082 1969 Coal 16.8 61 84 2.8/0.28
3
- ---------------------------------------------------------------------------------------------------------------------------------
Conemaugh 138 9,500 1970 Coal 21.6 60 85 0.7/0.25
Conemaugh(1) Coal 1(2)
--------------------------------------------------------------------------------------------------------------
Conemaugh 138 9,500 1970 Coal 21.6 60 85 0.7/0.25
Coal 2
- ---------------------------------------------------------------------------------------------------------------------------------
Keystone(1) Keystone 1(3) 105 9,190 1967 Coal 20.2 60 85 2.8/0.31
--------------------------------------------------------------------------------------------------------------
Keystone 2 105 9,190 1968 Coal 20.2 60 85 2.8/0.31
- ---------------------------------------------------------------------------------------------------------------------------------
Martins Creek Martins Creek 280 10,20 1954 Coal 22.2 25 82 2.8/0.38
Coal Coal 0
- ---------------------------------------------------------------------------------------------------------------------------------
Montour Coal Montour Coal 1,518 9,012 1972 Coal 14.5 50 83 2.8/0.04
- ---------------------------------------------------------------------------------------------------------------------------------
Peaking Units (Turbines)
- ---------------------------------------------------------------------------------------------------------------------------------
Brunner Island Brunner 9 10,00 1967 Diesel 3.7 -- 92 0/0.1
Diesel Island Diesel 0 /Oil
- ---------------------------------------------------------------------------------------------------------------------------------
Martins Creek Martins Creek 13,78 Diesel 3.7 -- 91 0/0.13
CT CT 72 3 1971 /Oil
- ---------------------------------------------------------------------------------------------------------------------------------
Hydro Units
- ---------------------------------------------------------------------------------------------------------------------------------
Holtwood Hydro Holtwood 102 -- 1910 Water 46.6 -- 64 --
Hydro
- ---------------------------------------------------------------------------------------------------------------------------------
Safe Harbor(4) Safe Harbor 139 -- 1931 Water 29.0 -- 29 --
- ---------------------------------------------------------------------------------------------------------------------------------
Wallenpaupack Wallenpaupack 44 -- 1926 Water 27.3 -- 20 --
- ---------------------------------------------------------------------------------------------------------------------------------
Nuclear Units
- ---------------------------------------------------------------------------------------------------------------------------------
Susquehanna(5) Susquehanna 1,965 10,48 1983 Nuke 83.0 -- 85 --
1
- ---------------------------------------------------------------------------------------------------------------------------------
Oil/Gas Steam Units
- ---------------------------------------------------------------------------------------------------------------------------------
Martins Creek 760 9,427 1977 Oil 5.4 22 80 3.3/0.3
Martins Creek (oil)
Oil/Gas Steam(6) ---------------------------------------------------------------------------------------------------------------
Martins Creek 900 9,467 1975 Gas 5.4 22 80 0/0.15
(gas)
- ---------------------------------------------------------------------------------------------------------------------------------
Peaking Units (LM6OOOs)
- ---------------------------------------------------------------------------------------------------------------------------------
Eden Eden 90 9,600 2002 Gas 9.8 -- 97 0/0.02
- ---------------------------------------------------------------------------------------------------------------------------------
West Earl West Earl 450 9,600 2003 Gas 9.8 -- 97 0/0.02
- ---------------------------------------------------------------------------------------------------------------------------------
Upper Hanover Upper Hanover 90 9,600 2003 Gas 9.8 -- 97 0/0.02
- ---------------------------------------------------------------------------------------------------------------------------------
Note: Only units analyzed directly in the study are shown. However, PPl owns an
additional 250 to 300 MW of peaking capacity in PJM.
1 PPL owns 16.25 percent of the total 850 MW of Conemaugh and 12.4 percent
of the total 850 MW of Keystone.
2 Unit retrofits with SCR in 2003 as specified by PPL, NO(x) emissions
decline to 0.05 lbs/MMBtu.
3 Unit retrofits with SCR in 2003 as specified by PPL, NO(x) emissions
decline to 0.06 lbs/MMBtu.
4 PPL owns 33 percent of the total 418 MW at Safe Harbor.
5 PPL owns 90 percent of the total 2,184 MW at the Susquehanna Nuclear
Station.
6 Martins Creek is capable of utilizing gas at 900 MW of the total 1660 MW
at the plant. To capture this, the unit level capacities have been
somewhat modified from actual.
- --------------------------------------------------------------------------------
154 [LOGO] ICF CONSULTING
Exhibit 6-5
PPL NEPOOL Generating Stations
[MAP]
The assets in NEPOOL are primarily hydro units acquired from Bangor Hydro.
In addition, PPL has partial ownership of the Wyman oil/gas steam unit in Maine
and is developer of a mid-level turbine in Connecticut.
- --------------------------------------------------------------------------------
155 [LOGO] ICF CONSULTING
Exhibit 6-6
Summary of PPL Asset Characteristics within NEPOOL
- -------------------------------------------------------------------------------------------------------------------------
Heat Fixed Minimum Avail SO(2)/NO(x)
Modeled Included Capacity Rate On-line Fuel O&M Turndown ability Rate
Unit Units (MW) (Btu/ Year Type (1998$/ (%) (%) (lbs/
kWh) kW) MMBtu)
- -------------------------------------------------------------------------------------------------------------------------
Oil/Gas Steam Units
- -------------------------------------------------------------------------------------------------------------------------
Wyman Wyman 4(1) 52 10,745 1978 Gas/ 5.4 25 82 0/0.12
Oil
- -------------------------------------------------------------------------------------------------------------------------
Hydro Units
- -------------------------------------------------------------------------------------------------------------------------
Howland 2 -- 1916 Water 17.3 -- 69 --
----------------------------------------------------------------------------------------------
Medway 11 -- 1923 Water 10.3 -- 69 --
----------------------------------------------------------------------------------------------
Milford 6 -- 1949 Water 10.8 -- 69 --
----------------------------------------------------------------------------------------------
Hydro Stillwater 2 -- 1949 Water 11.5 -- 69 --
Assets ----------------------------------------------------------------------------------------------
Veazie A 5 -- 1920 Water 7.6 -- 69 --
----------------------------------------------------------------------------------------------
Veazie B 3 -- 1938 Water 7.6 -- 69 --
----------------------------------------------------------------------------------------------
West 13 -- 1988 Water 10.6 -- 69
Enfield
- -------------------------------------------------------------------------------------------------------------------------
Ellsworth Ellsworth 9 -- 1919 Water 10.7 -- 38 --
- -------------------------------------------------------------------------------------------------------------------------
Peaking Units (LM6000s)
- -------------------------------------------------------------------------------------------------------------------------
Wallingford 220 9,600 2001 Gas 9.8 -- 97 --
- -------------------------------------------------------------------------------------------------------------------------
1 PPL owns 52 MW of the 615 MW Wyman 4 unit.
Exhibit 6-7
PPL Montana, Arizona, and PacNW Generating Stations
[MAP]
As in NEPOOL, PPL acquired existing capacity in the Montana market. The
assets in Montana are consist only of hydro and coal capacity and are considered
as low variable cost baseload units. PPL is also establishing a presence in the
Pacific Northwest with a large
- --------------------------------------------------------------------------------
156 [LOGO] ICF CONSULTING
combined cycle facility that is under development. The WSCC market area is
geographically broad and has several diverse subregions. PPL's major presence is
in the Northwest, but they are also expanding to the capacity short southwest
though the addition of a combined cycle facility with duct firing capability and
a peaking unit in Arizona.
Exhibit 6-8
Summary of PPL Asset Characteristics within Arizona, Montana, and the Pacific
Northwest
- ------------------------------------------------------------------------------------------------------------------------
Modeled Included Capacity Heat On- Fuel Annual Mini- Availa- SO(2)
Unit Units (MW) Rate line Type Fixed mum bility Rate
(Btu/ Year O&M Turn (%) (lbs/
kWh) ($/kW) down MMBtu)
(%)
- ------------------------------------------------------------------------------------------------------------------------
Coal Units
- ------------------------------------------------------------------------------------------------------------------------
Corette Corette 156 11,011 1968 Coal 22.2 40 88 1.18
- ------------------------------------------------------------------------------------------------------------------------
Colstrip(1) Colstrip 530 10,818 1986 Coal 11.1 40 87 0.15
- ------------------------------------------------------------------------------------------------------------------------
Hydro Units
- ------------------------------------------------------------------------------------------------------------------------
Black Eagle 16.8 -- 1927 Water 3.6 -- 70 --
------------------------------------------------------------------------------------------------------
Cochrane 54 -- 1958 Water 1.1 -- 70 --
------------------------------------------------------------------------------------------------------
Hauser Lake 17 -- 1911 Water 2.3 -- 70 --
------------------------------------------------------------------------------------------------------
Holter 50 -- 1918 Water 1.9 -- 70 --
------------------------------------------------------------------------------------------------------
Montana Morony 48 -- 1930 Water 1.5 -- 70 --
Hydro ------------------------------------------------------------------------------------------------------
Assets Mystic Lake 12 -- 1925 Water 4.9 -- 70 --
------------------------------------------------------------------------------------------------------
Rainbow Mtn 35.6 -- 1910 Water 2.5 -- 70 --
------------------------------------------------------------------------------------------------------
Ryan 60 -- 1915 Water 1.6 -- 70 --
------------------------------------------------------------------------------------------------------
Madison Mtn 9 -- 1906 Water 6.8 -- 70 --
------------------------------------------------------------------------------------------------------
Kerr 168 -- 1938 Water 11.0 -- 70 --
------------------------------------------------------------------------------------------------------
Thompson 86 -- 1915 Water 1.7 -- 70 --
Falls
- ------------------------------------------------------------------------------------------------------------------------
Combined Cycle Units
- ------------------------------------------------------------------------------------------------------------------------
Griffith(2) Griffith 210 6,900 2001 Gas 17.3 -- 92 --
- ------------------------------------------------------------------------------------------------------------------------
Griffith Duct(2) Griffith Duct 60 9,200 2001 Gas 17.3 -- 92 --
- ------------------------------------------------------------------------------------------------------------------------
Starbuck Starbuck 1,200 6,753 2004 Gas 17.3 -- 92 --
- ------------------------------------------------------------------------------------------------------------------------
Peaking Units (LM6000s)
- ------------------------------------------------------------------------------------------------------------------------
Sundance Sundance 440 9,600 2002 Gas 9.8 -- 92 --
- ------------------------------------------------------------------------------------------------------------------------
1 PPL owns 50 percent of Colstrip Units 1 & 2, and 30 percent of Unit 3.
2 PPL owns 50 percent of Griffith Power Plant.
In addition to the generating stations described above, PPL is developing
in the Midwest and the New York markets. Currently, development plans call for
the addition of 270MW of mid-level to peaking capacity in Long Island and for
540MW near Chicago in the ComEd territory. Descriptions of these units are
found in Exhibit 6-9.
- --------------------------------------------------------------------------------
157 [LOGO] ICF CONSULTING
Exhibit 6-9
Summary of PPL Asset Characteristics of Units Under Development in LILCO and
MAIN
- -------------------------------------------------------------------------------------------------------------------------------
Modeled Region Capacity Heat Rate On- Fuel Annual Minimum Availability SO(2)/NO(x)
Unit (MW) (Btu/ Line Type Fixed Turndown (%) Rate
kWh) Year O&M (%) (lbs.MMBtu)
($/kW)
- -------------------------------------------------------------------------------------------------------------------------------
Peaking Units (LM6000s)
- -------------------------------------------------------------------------------------------------------------------------------
Kings LILCO 270 9,600 2003 Gas 9.8 -- 97 0/0.02
Park
- -------------------------------------------------------------------------------------------------------------------------------
University ComEd 540 9,600 2002 Gas 9.8 -- 97 0/0.02
- -------------------------------------------------------------------------------------------------------------------------------
Summary of Generation Assets by Asset Type
Exhibit 6-10
Summary of PPL Asset Characteristics by Unit Type
- -------------------------------------------------------------------------------------------------------------------------
Parameter Hydro Nuclear Coal Combined Oil/Gas Peaking Total
Cycle Steam Units
- -------------------------------------------------------------------------------------------------------------------------
Number of 102 2 14 4 3 15 140
Generators(1)
- -------------------------------------------------------------------------------------------------------------------------
Total Capacity(2) 892 2,057 4,419 2,072 1,712 2,181 13,334
- -------------------------------------------------------------------------------------------------------------------------
Average Heat Rate(3) 0 10,481 9,657 6,859 10,745 9,618 8,926
- -------------------------------------------------------------------------------------------------------------------------
Average Fuel Costs(4) 0.0 5.8 9.6 19.4 0.0 29.5 10.2
- -------------------------------------------------------------------------------------------------------------------------
NPV of Dispatch 1,400 2,169 4,975 1,114 1,009 1,088 11,755
Revenues($000)(5)
- -------------------------------------------------------------------------------------------------------------------------
NPV of Dispatch 1,569 1,054 1,126 538 589 499 882
Revenues
(1998$/kW)(5)
- -------------------------------------------------------------------------------------------------------------------------
Note: Includes existing units, units currently under construction, and any
firmly planned capacity additions. Values calculated for PPL owned portions
only.
1 Number of physical generating units at the PPL assets analyzed herein. PPL
owns additional peaking capacity in PJM.
2 Includes planned capacity uprates.
3 Weighted by generation for 2005.
4 Represents projections for 2005, weighted by generation.
5 NPV is calculated using an 11.2 percent real discount rate and does not
include taxes, debt, or some cost items such as new capital additions.
Includes revenues, short-run variable costs and estimated non-fuel O&M.
Coal Units
Of the currently or soon to be operating units owned by PPL, a total of
4.4 GW are coal units. Of this, roughly 84 percent of the total capacity is in
PJM with the remainder in Montana. There are five coal units in PJM West with a
total capacity of 3.7 GW and an average heat rate of 9,253 Btu/kWh. These units
are among the most efficient units in the region and also have relatively low
environmental costs and high availability. The Montour, Conemaugh and Keystone
plants have NO(x) control technology in place and are expected to be very
competitive, even under SIP Call constraints. The availability of all the plants
under analysis is between 82 percent and 88 percent.
- --------------------------------------------------------------------------------
158 [LOGO] ICF CONSULTING
Exhibit 6-11
Summary Capacity Block Characteristics -- PPL PJM Coal Plants
- -------------------------------------------------------------------------------------------------------------
Parameter Martins Creek Montour Brunner Island
- -------------------------------------------------------------------------------------------------------------
Region PJM PJM PJM
- -------------------------------------------------------------------------------------------------------------
Number of capacity blocks 1 1 2 (units 1 & 2, unit
3)
- -------------------------------------------------------------------------------------------------------------
Summer Capacity (MW) 280 1,518 699 735
- -------------------------------------------------------------------------------------------------------------
Turndown (%) 25(1) 5(1) 43.2(1) 61(1)
- -------------------------------------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 22.2 14.5 16.8
- -------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)-- Full 10,200(1) 9,012 9,179 9,082
Load
- -------------------------------------------------------------------------------------------------------------
Coal - Central PA, Coal - Central
Primary Fuel Central Appalachia Coal - Central PA Appalachia and
and South Western and South Western South Western PA
PA Bituminous(1) PA Bituminous(1) Bituminous(1)
- -------------------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2001 1.73 1.64 1.61
2005 1.38 1.30 1.26
2010 1.37 1.30 1.27
2015 1.31 1.24 1.22
2020 1.25 1.19 1.17
- -------------------------------------------------------------------------------------------------------------
SO(2) Rate (lbs/MMBtu) 2.8(1) 2.8(1) 2.8(1)
- -------------------------------------------------------------------------------------------------------------
NO(x) Rate (lbs/MMBtu) 0.4 Uncontrolled/ 0.31(1) 0.28(1)
0.38 0.04 Controlled(1)
- -------------------------------------------------------------------------------------------------------------
NO(x) Control Technology Selective Catalytic None
None Reduction - SCR(1)
- -------------------------------------------------------------------------------------------------------------
Availability (%) 81.5(1) 82.5(1) 84.1(1) 84.0(1)
- -------------------------------------------------------------------------------------------------------------
1 Assumption provided by PPL.
- --------------------------------------------------------------------------------
159 [LOGO] ICF CONSULTING
Exhibit 6-11 (continued)
Summary Capacity Block Characteristics -- PPL PJM Coal Plants
- --------------------------------------------------------------------------------------------------------------
Parameter Conemaugh Keystone
- --------------------------------------------------------------------------------------------------------------
Region PJM PJM
- --------------------------------------------------------------------------------------------------------------
Number of capacity blocks 2 2
- --------------------------------------------------------------------------------------------------------------
Summer Capacity (MW) 138 138 105 106
- --------------------------------------------------------------------------------------------------------------
Turndown (%) 60 60
- --------------------------------------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 21.6 20.3
- --------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh) - Full Load 9,500(1) 9,190(1)
- --------------------------------------------------------------------------------------------------------------
Pennsylvania Bituminous Pennsylvania Bituminous
Coal, 2.3 percent sulfur, Coal, 1.75 percent sulfur,
Primary Fuel 12,600 Btu/lb(1) 12,500 Btu/1b(1)
- --------------------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2001 1.35 1.35
2005 1.03 1.03
2010 1.05 1.05
2020 0.99 0.99
- --------------------------------------------------------------------------------------------------------------
SO(2) Rate (lbs/MMBtu) 0.07 2.8
- --------------------------------------------------------------------------------------------------------------
0.25 ozone 0.25 ozone 0.31 ozone 0.31 ozone
season, 0.05 season(1) season, 0.06 season(1)
NO(x) Rate (lbs/MMBtu) with SCR(1) with SCR(1)
- --------------------------------------------------------------------------------------------------------------
Availability (%) 87 87 87
- --------------------------------------------------------------------------------------------------------------
Note: PPL owns 16.3 percent of Conemaugh and 12.4 percent of Keystone.
1 Assumption provided by PPL.
The two coal plants in the Montana region account for the remainder of
the PPL coal units. As in PJM, the Monttma coal units are relatively low cost
and efficient units in the WSCC.
Exhibit 6-12
Summary Capacity Block Characteristics -- PPL Montana Coal Plants
- --------------------------------------------------------------------------------------------------------------
Parameter Colstrip Corette
- --------------------------------------------------------------------------------------------------------------
Region Montana Montana
- --------------------------------------------------------------------------------------------------------------
Number of capacity blocks 1 1
- --------------------------------------------------------------------------------------------------------------
Summer Capacity (MW) 530(1) 156
- --------------------------------------------------------------------------------------------------------------
Turndown (%) 40 40
- --------------------------------------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 11.07 22.2
- --------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)-- Full Load 10,818 11,011
- --------------------------------------------------------------------------------------------------------------
Primary Fuel Montana Powder River Basin Wyoming Powder River Basin
- Sub-bituminous - Sub-bituminous
- --------------------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2001 0.96 0.83
2005 0.68 0.47
2010 0.65 0.45
2020 0.60 0.42
- --------------------------------------------------------------------------------------------------------------
SO(2) Rate (lbs/MMBtu) 0.15 1.18
- --------------------------------------------------------------------------------------------------------------
Availability (%) 86.6 87.7
- --------------------------------------------------------------------------------------------------------------
1 PPL owns 50 percent of Colstrip 1 and 2, and 30 percent each of Colstrip 3
and 4.
- --------------------------------------------------------------------------------
160 [LOGO] ICF CONSULTING
Exhibit 6-13 provides summary description of the historical performance of
the PPL coal units.
Exhibit 6-13
Historical Capacity Factor at PPL Coal Units
- --------------------------------------------------------------------------------------------------
2001-
Region/Plant 1997 1998 1999 2000 Average 2001 2020
Forecast Forecast
Average
- --------------------------------------------------------------------------------------------------
PJM
- --------------------------------------------------------------------------------------------------
Brunner Island
Coal(1) 64% 64% 62% 73% 65% 84% 80%
- --------------------------------------------------------------------------------------------------
Martin's Creek
Coal(1) 65% 44% 32% 46% 47% 67% 57%
- --------------------------------------------------------------------------------------------------
Montour Coal(1) 67% 71% 68% 63% 68% 81% 81%
- --------------------------------------------------------------------------------------------------
Conemaugh
Coal 94% 88% 76% 81% 85% 84% 87%
- --------------------------------------------------------------------------------------------------
Keystone Coal 89% 86% 78% 83% 84% 84% 87%
- --------------------------------------------------------------------------------------------------
Montana
- --------------------------------------------------------------------------------------------------
Colstrip Coal 75% 87% 82% 79% 81% 86% 86%
- --------------------------------------------------------------------------------------------------
Corette Coal 53% 42% 74% 86% 61% 88% 88%
- --------------------------------------------------------------------------------------------------
Source: Historical data from EIA Form 759; forecast data from ICF.
1 Data only available through June 2000. Average based on half year value
through year 2000.
As can be seen, the PJM coal units have historically operated very well,
in particular, the Keystone, Conemaugh, and Montour units had consistently
strong performance. Over time, we project that these units will continue to
dispatch to near their full availability, in addition, the dispatch of Brunner
Island is expected to improve significantly.
Exhibit 6-14
Historical Fuel Prices at Major PPL Coal Stations (1998$)
- --------------------------------------------------------------------------------------------------
Region/Plant 1997 1998 1999 2000 Average 2001
Forecast
- --------------------------------------------------------------------------------------------------
PJM
- --------------------------------------------------------------------------------------------------
Brunner Island Coal 1.54 1.52 1.45 1.45 1.49 1.61
- --------------------------------------------------------------------------------------------------
Martin's Creek Coal 1.31 1.34 1.27 1.31 1.31 1.73
- --------------------------------------------------------------------------------------------------
Montour Coal 1.46 1.43 1.36 1.37 1.41 1.64
- --------------------------------------------------------------------------------------------------
Conemaugh Coal 1.18 1.08 1.05 1.07 1.10 1.35
- --------------------------------------------------------------------------------------------------
Keystone Coal 1.32 1.29 1.29 1.08 1.25 1.35
- --------------------------------------------------------------------------------------------------
Montana
- --------------------------------------------------------------------------------------------------
Colstrip Coal 0.69 0.67 0.73 0.62 0.68 0.96
- --------------------------------------------------------------------------------------------------
Corette Coal 0.57 0.54 0.72 0.83
- --------------------------------------------------------------------------------------------------
Source: Historical data from FERC Form 423 data as reported in CoalDat;
Forecasts by ICF. CoalDat weighted average of spot and contract is shown.
- --------------------------------------------------------------------------------
161 [LOGO] ICF CONSULTING
Exhibit 6-15
Projected Coal Costs (1998$)
- -------------------------------------------------------------------------------------------------------------
Delivered Price
Coal Type Trans- Forecast
(Sulfur Commodity portation ----------------------
Region/Plant Year Content) Price ($/ton) ($/ton) $/ton $/MMBtu
(MMBtu/ton)
- -------------------------------------------------------------------------------------------------------------
PJM
- -------------------------------------------------------------------------------------------------------------
2001 30.85 9.30 40.15 1.61
Brunner Island 2010 2.8 23.88 7.76 31.64 1.27
Coa 2020 22.89 6.34 29.23 1.17
- -------------------------------------------------------------------------------------------------------------
2001 30.85 12.32 43.17 1.73
Martin's Creek 2010 2.8 23.88 10.27 34.15 1.37
Coal 2020 22.89 8.39 31.28 1.25
- -------------------------------------------------------------------------------------------------------------
2001 30.85 10.23 41.08 1.64
Montour Coal 2010 2.8 23.88 8.54 32.42 1.30
2020 22.89 6.97 29.86 1.19
- -------------------------------------------------------------------------------------------------------------
2001 30.85 2.80 33.65 1.35
Conemaugh 2010 2.8 23.88 2.34 26.22 1.05
Coal 2020 22.89 1.91 24.80 0.99
- -------------------------------------------------------------------------------------------------------------
2001 30.85 2.80 33.65 1.35
Keystone Coal 2010 2.8 23.88 2.34 26.22 1.05
2020 22.89 1.91 24.80 0.99
- -------------------------------------------------------------------------------------------------------------
Montana
- -------------------------------------------------------------------------------------------------------------
2001 10.74 5.59 16.33 0.96
Colstrip Coal 2010 1.8 6.40 4.66 11.06 0.65
2020 6.40 3.81 10.21 0.60
- -------------------------------------------------------------------------------------------------------------
2001 9.42 4.65 14.07 0.83
Corette Coal 2010 1.2 3.70 3.88 7.58 0.45
2020 3.92 3.17 7.09 0.42
- -------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
162 [LOGO] ICF CONSULTING
Exhibit 6-16
Coal Unit Environmental Compliance
- ------------------------------------------------------------------------------------------------------------------------
Environ- Firmly % Seasonal Fixed
Region/Plant Year mental Planned or Emission Cost O&M
Control Model Reduction Adder Adder
Decision ($/MWh) ($/MWh)
- ------------------------------------------------------------------------------------------------------------------------
PJM
- ------------------------------------------------------------------------------------------------------------------------
Brunner Island Coal 1&2 -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------
Brunner Island Coal 3 2005 SCR Model Decision 97 0.24 4.45
- ------------------------------------------------------------------------------------------------------------------------
Martin's Creek Coal - - - - - -
- ------------------------------------------------------------------------------------------------------------------------
Montour Coal 2001 SCR Firmly Planned 96 0.25 4.45
- ------------------------------------------------------------------------------------------------------------------------
Conemaugh Coal 1(1) 2003 SCR Firmly Planned 95 0.25 4.45
- ------------------------------------------------------------------------------------------------------------------------
Conemaugh Coal 2(1) 2003 SCR Model Decision 85 0.25 4.45
- ------------------------------------------------------------------------------------------------------------------------
Keystone Coal 1(2) 2003 SCR Firmly Planned 94 0.25 4.45
- ------------------------------------------------------------------------------------------------------------------------
Keystone Coal 2(2) 2010 SCR Model Decision 94 0.25 4.45
- ------------------------------------------------------------------------------------------------------------------------
Montana
- ------------------------------------------------------------------------------------------------------------------------
Colstrip Coal - - - - - -
- ------------------------------------------------------------------------------------------------------------------------
Corette Coal - - - - - -
- ------------------------------------------------------------------------------------------------------------------------
1. PPL owns 16.25 percent of Conemaugh.
2. PPL owns 12.4 percent of Keystone.
Source: Historical data from FERC Form 423 data as reported in CoalDat;
forecasts by ICF.
ICF has evaluated the proposed NO(x) legislation and associated required
compliance factors to determine what the most likely NO~ program would be. This
evaluation included review of current programs, proposed legislation, required
time for compliance, cost for compliance, pending legislation, and likely
reaction. In all likelihood, the NO(x) program features will be very similar to
the SIP Call proposals, however, implementation for non-OTR regions will be
delayed until 2004. Under this program we have also determined the optimal
compliance strategy for each generating unit. The NO(x) control decisions by
plant are presented in Exhibit 6-16. The ICF Base Case modeling incorporates
these compliance decisions into the operating characteristics of the units. As
such, all variable costs associated with installation of the NO(x) controls have
been incorporated to our dispatch analysis. Note, however, that our pro formas
do not capture the initial capital expenditure but do capture the variable and
fixed costs going forward.
Under the Base Case, compliance decisions impact more than 90 percent of
the 3,700 PPL coal plants in PJM. Currently, three generators have planned SCR
installation in the near-term. In addition, our model has determined that an
additional 3 generators should install equipment by between 2003 and 2010.
Note that in addition to the SIPCa11 program, the PPL Pennsylvania and New
England units are subject to OTR compliance programs in 2000 and beyond. As
such, these units are less
- --------------------------------------------------------------------------------
163 [LOGO] ICF CONSULTING
competitive in the near term than the non-OTR units. Despite this competitive
disadvantage, given the low variable costs for most of the units, compliance
control technologies are not required until the more stringent SIPCall standards
set in 2003.
Compliance with SO(2) emissions restrictions is much less of a problem
than with NO(x). Note that several facilities have existing scrubber technology
installed. ICF forecasts no additional scrubber retrofits at PPL generating
stations. Neither do we see significant fuel switching among the units.
The Montana units are not subject to either the OTR or SIPCall legislation
but are subject to the national SO2 standards..
Hydro Units
ICF is analyzing six hydro capacity blocks for PPL. Three of the units,
Wallenpaupack, Holtwood, and Safe Harbor, are located in the western PJM
sub-region. We model the remaining units as two capacity blocks in NEPOOL and
one in Montana.. The units in the "Run of River" capacity block in NEPOOL are
Howland (2 MW), Medway (3.4 MW), Milford (8 MW), Stillwater (2 MW), Veazie A&B
(7.3 MW), and West Enfield (19.5 MW). Additionally, the Ellswoth unit has
storage capability and is modeled as a separate capacity block. The units
comprising the Montana hydro block are: Black Eagle (16.8 MW), Cochrane (54 MW),
Hauser Lake (17 MW), Holter (50 MW), Morony (48 MW), Mystic Lake (12 MW),
Rainbow Mountain (35.6), Ryan (60 MW), Madison Mountain (9 MW), Kerr (168 MW),
Thompson (86 MW). There are a total of 1,060 MW of run of river capacity and 111
MW of storage capable peaking capacity.
Exhibit 6-17
PPL Hydro Plant Characteristics
- -----------------------------------------------------------------------------------------------------------------------
Fixed Historical
Summer Reserve O&M Storage Annual Forecasted
Model Capacity Contribution (1998$/ Capability Availability Availability
Region/Plant Units (MW) (MW) kWyr) (%) (%)
- -----------------------------------------------------------------------------------------------------------------------
PJM
- -----------------------------------------------------------------------------------------------------------------------
Wallenpaupack 1 44 44 27.0 No 20.3 20.3
- -----------------------------------------------------------------------------------------------------------------------
Holtwood 1 102 102 46.6 Yes 64.3 64.3
- -----------------------------------------------------------------------------------------------------------------------
Safe Harbor(1) 1 139 139 29.0 No 29.1 29.1
- -----------------------------------------------------------------------------------------------------------------------
NEPOOL
- -----------------------------------------------------------------------------------------------------------------------
Hydro Block 1 1 42 42 10.7 No 64.0 64.0
- -----------------------------------------------------------------------------------------------------------------------
Ellsworth 1 9 9 10.7 Yes 38.0 38.0
- -----------------------------------------------------------------------------------------------------------------------
Montana
- -----------------------------------------------------------------------------------------------------------------------
Hydro Assets 1 556 482 4.7 No 70.0 70.0
- -----------------------------------------------------------------------------------------------------------------------
Source: Specific data provided by PPL to supplement ICF data.
1 PPL owns 1/3 of 418 MW at Safe Harbor.
Of the existing PPL assets, the hydro units account for roughly 900MW of
the near 11,000 MW total. The hydro assets are split across Montana, PJM and
NEPOOL. These units perform very well over time and on average have among the
highest contribution to PPL dispatch revenues on a per kilowatt basis.
- --------------------------------------------------------------------------------
164 [LOGO] ICF CONSULTING
Exhibit 6-18
Annual Hydro Capacity Factors (%)
- ---------------------------------------------------------------------------------------------------
Historical
Region/Plant -------------------------------------------------------- Forecast
1994 1995 1996 1997 1998 1999
- ---------------------------------------------------------------------------------------------------
PJM
- ---------------------------------------------------------------------------------------------------
Wallenpaupack(1) -- 16.6 35.0 14.4 24.0 14.4 20.3(2)
- ---------------------------------------------------------------------------------------------------
Holtwood(1) -- 56.1 71.0 60.8 58.6 58.0 64.3(2)
- ---------------------------------------------------------------------------------------------------
Safe Harbor(1) -- 23.5 39.7 24.9 31.4 22.2 29.1(2)
- ---------------------------------------------------------------------------------------------------
NEPOOL
- ---------------------------------------------------------------------------------------------------
Medway 95.5 77.4 96.8 97.2 99.7 100.0
- ---------------------------------------------------------------------------------------
Howland 42.6 49.5 46.0 46.2 45.8 53.3
- ---------------------------------------------------------------------------------------
Milford 80.7 74.2 87.1 76.0 89.0 85.0 64.0
- ---------------------------------------------------------------------------------------
Stillwater 64.3 69.7 60.2 72.0 62.9 71.9
- ---------------------------------------------------------------------------------------
Veazie 70.3 69.5 74.2 63.9 63.5 83.5
- ---------------------------------------------------------------------------------------
West Enfield 70.0 78.9 99.6 75.8 83.1 92.2
- ---------------------------------------------------------------------------------------------------
Ellsworth 35.1 35.5 47.7 33.4 31.2 40.2 38.0
- ---------------------------------------------------------------------------------------------------
Montana(2)
- ---------------------------------------------------------------------------------------------------
Hydro Assets 44.4 50.6 59.2 60.1 54.5 53.8 70.0
- ---------------------------------------------------------------------------------------------------
1 Source: EIA Form 759
2 Source: PPL
Historical capacity factors at the eastern these units have been
relatively stable over time. The Montana units tend to have the largest
variation in capacity factor, contributing to this is both the size and
capability of the units, and the greater degree of variability in the weather
northwest rain and run-off patterns.
- --------------------------------------------------------------------------------
165 [LOGO] ICF CONSULTING
Exhibit 6-19
Projected Monthly Hydro Plant Availability
- ---------------------------------------------------------------------------------------------------------------------
Monthly
Availability (%) Jan Feb Mar Apr May Jun July Aug Sep Oct Nov Dec
- ---------------------------------------------------------------------------------------------------------------------
PJM
- ---------------------------------------------------------------------------------------------------------------------
Wallenpaupack 22.3 26.2 18.9 21.1 19.2 17.4 18.6 15.6 14.8 20.2 22.3 26.2
- ---------------------------------------------------------------------------------------------------------------------
Holtwood 69.8 75.9 92.2 91.2 85.7 65.4 47.4 36.9 34.4 40.8 61.3 71.2
- ---------------------------------------------------------------------------------------------------------------------
Safe Harbor 30.3 35.1 55.5 56.7 40.5 23.4 15.0 10.8 10.2 15.3 25.2 32.1
- ---------------------------------------------------------------------------------------------------------------------
NEPOOL
- ---------------------------------------------------------------------------------------------------------------------
Medway 94 96 97 99 92 97 93 91 92 91 91 91
- ---------------------------------------------------------------------------------------------------------------------
Howland 45 44 49 37 54 62 31 29 33 57 68 56
- ---------------------------------------------------------------------------------------------------------------------
Milford 86 84 86 77 91 98 88 83 86 91 94 90
- ---------------------------------------------------------------------------------------------------------------------
Stillwater 78 80 79 69 71 77 76 73 75 75 75 74
- ---------------------------------------------------------------------------------------------------------------------
Veazie 79 76 78 71 79 84 77 72 76 83 87 80
- ---------------------------------------------------------------------------------------------------------------------
West Enfield 74 77 95 100 100 89 71 62 66 78 93 83
- ---------------------------------------------------------------------------------------------------------------------
Ellsworth 100 100 100 100 100 94 65 59 57 70 82 100
- ---------------------------------------------------------------------------------------------------------------------
Montana
- ---------------------------------------------------------------------------------------------------------------------
Hydro Assets 72 67 68 67 81 83 74 74 60 63 64 67
- ---------------------------------------------------------------------------------------------------------------------
Source: Average historical operation calculated from time series provided by
PPL.
The configurations of the hydro units tend to vary significantly across
regions. The Montana units are well located and tend to have fairly consistent
year round operation while the eastern run of river units have much lower annual
capacity factors. Also note that two of the eastern units have storage
capability and as such have much higher dispatch than the run of river units in
the same regions.
Nuclear
Exhibit 6-20
PPL Nuclear Plant Characteristics
- --------------------------------------------------------------------------------
Parameter Susquehanna(1)
- --------------------------------------------------------------------------------
Region PJM
- --------------------------------------------------------------------------------
Number of capacity blocks 1
- --------------------------------------------------------------------------------
Summer Capacity (MW) 2,286
- --------------------------------------------------------------------------------
Turndown (%) --
- --------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 83.0
- --------------------------------------------------------------------------------
Variable O&M (1998$/kWyr) 1.0
- --------------------------------------------------------------------------------
Heat Rate (Btu/kWh) - Full Load 10,481
- --------------------------------------------------------------------------------
Primary Fuel Nuclear
- --------------------------------------------------------------------------------
Delivered Fuel Price (1998$/MMBtu)
2000 0.55
2005 0.55
2010 0.55
2020 0.55
- --------------------------------------------------------------------------------
Availability (%) 88.0
- --------------------------------------------------------------------------------
1 PPL owns 90 percent of 2,286 MW at Susquehanna Station.
ICF is analyzing one nuclear unit for PPL. Susquehanna is a 2,184 MW unit
in western PJM of which PPL owns 90 percent. The Susquehanna station performs
well over the course of this study with an expected annual average capacity
factor of 85 percent.
- --------------------------------------------------------------------------------
166 [LOGO] ICF CONSULTING
Oil/Gas Steam Units
Exhibit 6-21
PPL Oil/Gas Steam Plant Characteristics
- ----------------------------------------------------------------------------------------------------
Parameter Martins Creek Wyman Unit 4(1)
- ----------------------------------------------------------------------------------------------------
Region PJM NEPOOL
- ----------------------------------------------------------------------------------------------------
Number of capacity blocks 2 1
- ----------------------------------------------------------------------------------------------------
Summer Capacity (MW) 900(2) 760(2) 52
- ----------------------------------------------------------------------------------------------------
Turndown (%) 22 25
- ----------------------------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 5.4 5.36
- ----------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh) - Full
Load 10,600(2) 10,745
- ----------------------------------------------------------------------------------------------------
Primary Fuel Natural Gas 3% Resid Oil Natural Gas 3% Resid Oil
- ----------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2001 5.22 3.28 5.61 3.27
2005 2.92 2.79 3.20 2.78
2010 3.03 2.93 3.35 2.91
2020 3.19 3.06 3.45 3.04
- ----------------------------------------------------------------------------------------------------
SO(2) Rate (lbs MMBtu) 0(2) 1.03(2) 0
- ----------------------------------------------------------------------------------------------------
NO(x) Rate (lbs/MMBtu) 0.23 0.12(2)
- ----------------------------------------------------------------------------------------------------
Availability (%) 80(2) 80(2)
- ----------------------------------------------------------------------------------------------------
1 PPL owns 52 MW of 616 MW at Wyman 4.
2 Assumption provided by PPL.
Due to gas constraint at the Facility, Martins Creek is restricted to operating
900 MW on gas at any point in time. As such, the plant has been modeled as two
equivalent units, one operating on gas only, and the other on oil.
There are two large oil/gas steam units under analysis. Martins Creek in
PJM West and Wyman Unit 4 in NEPOOL. Martins Creek is the only oil/gas steam
generator in ICF's characterization of the PJM West region.
- --------------------------------------------------------------------------------
167 [LOGO] ICF CONSULTING
Combined Cycle Units
Exhibit 6-22
PPL Combined Cycle Plant Characteristics
- ------------------------------------------------------------------------------------------------------
Mount Mount Griffith Griffith
Parameter Bethel Bethel Energy Duct Starbuck
Project Duct Project
- ------------------------------------------------------------------------------------------------------
Region PJM Arizona PacNW
- ------------------------------------------------------------------------------------------------------
Number of capacity blocks 1 1 1 1 1
- ------------------------------------------------------------------------------------------------------
On-line Date 2002 2001 2004
- ------------------------------------------------------------------------------------------------------
Summer Capacity (MW) 520 82 210(1) 60(1) 1,200
- ------------------------------------------------------------------------------------------------------
Turndown (%) -- -- --
- ------------------------------------------------------------------------------------------------------
Fixed O&M (1998$/kW/yr) 16.0 9.8 17.3
- ------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh) - Full
Load 6,928 9,675 6,900 9,000 6,753
- ------------------------------------------------------------------------------------------------------
Primary Fuel Natural Gas Natural Gas Natural
Gas
- ------------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2000 5.22 5.34 5.00
2005 2.92 2.80 2.71
2010 3.03 2.91 2.82
2020 3.19 2.38 2.04
- ------------------------------------------------------------------------------------------------------
SO(2) Rate (lbs/MMBtu) 0 0 0
- ------------------------------------------------------------------------------------------------------
NO(x) Rate (lbs/MMBtu) 0.2 0.1 0.2 N/A
- ------------------------------------------------------------------------------------------------------
Availability (%) 92.0 92.0 92.0
- ------------------------------------------------------------------------------------------------------
1 PPL owns 50 percent of the Griffith power plant.
PPL is developing three new combined cycles, one in PJM West, one in
Arizona, and one in the Pacific Northwest. Mount Bethel in Eastern Pennsylvania
is scheduled to be on-line in 2002 while the Griffith Energy Center in Arizona
will begin operation in 2001 as scheduled. ICF has modeled each of these units
as two discrete units. A combined cycle portion as well as the duct-firing
component as described above. PPL has more recently planned the addition of a
1200MW combined cycle facility in the Pacific Northwest. This unit is expected
to be on-line in 2004.
Peaking Units
Six sets of peaking units are evaluated in this analysis, five of which
are located in various regions of the Eastern Interconnect with the remaining
unit located in the WSCC in Arizona. The Martins Creek and Brunner Island
peakers have been on-line since the early 1970s. They have among the most
efficient turbine (with the lowest heat rates) in the region although generation
is expected to remain low. The Wallingford LM6000 unit is scheduled to come on-
line in 2001 in NEPOOL. It is expected to serve the need for expanded peaking
capability well and to be competitive with other units in the region.
Additional units PPL is considering include several additional sites for
locating LM6000 facilities. There are three sites in PJM East, one in Arizona,
one in ComEd, and one in Long Island. These facilities represent extremely
flexible capacity that will be able to operate to specific needs in each of the
areas.
- --------------------------------------------------------------------------------
168 [LOGO] ICF CONSULTING
Exhibit 6-23
PPL Peaking and Mid-Level Plant Characteristics
- ------------------------------------------------------------------------------------------------------------------
Parameter Martins Creek Brunner Island Wallingford Sundance
- ------------------------------------------------------------------------------------------------------------------
Region PJM PJM NEPOOL AZ/NM
- ------------------------------------------------------------------------------------------------------------------
Number of capacity
blocks 1 1 1 1
- ------------------------------------------------------------------------------------------------------------------
On-line Date 1971 1967 2001 2002
- ------------------------------------------------------------------------------------------------------------------
Summer Capacity
(MW) 72 9 220 440
- ------------------------------------------------------------------------------------------------------------------
Turndown (%) -- -- -- --
- ------------------------------------------------------------------------------------------------------------------
Fixed O&M
(1998$/kW/yr) 3.73 3.7 9.8 9.8
- ------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- - Full Load 13,850 10,000 9,600 9,600
- ------------------------------------------------------------------------------------------------------------------
Distillate Distillate Distillate
Primary Fuel Oil Gas Oil(1) Gas Oil Gas Gas
- ------------------------------------------------------------------------------------------------------------------
Delivered Fuel Price
(1998$/MMBtu)
2000 5.44 5.22 5.44 5.22 4.02 5.61 5.34
2005 2.93 2.92 2.93 2.92 2.63 3.20 2.80
2010 3.57 3.03 3.57 3.03 3.08 3.35 2.91
2020 3.57 3.19 3.57 3.19 3.18 3.45 2.38
- ------------------------------------------------------------------------------------------------------------------
SO(2) Rate
(lbs/MMBtu) 0.3/0.0 0.3/0.0 0.3/0.0 0.0
- ------------------------------------------------------------------------------------------------------------------
NO(x) Rate
(lbs/MMBtu) 0.13 0.10 0.1(2) N/A
- ------------------------------------------------------------------------------------------------------------------
Availability (%) 91.0 92.1 97.0 92.0
- ------------------------------------------------------------------------------------------------------------------
1 Representative of diesel fuel pricing.
2 Assumption provided by PPL.
- --------------------------------------------------------------------------------
169 [LOGO] ICF CONSULTING
Exhibit 6-23 (continued)
PPL LM6000 Plant Characteristics
- --------------------------------------------------------------------------------------------------------
Parameter Eden Upper West Earl Kings Park University
Hanover
- --------------------------------------------------------------------------------------------------------
Region PJM East PJM East PJM East LILCO ComEd
- --------------------------------------------------------------------------------------------------------
Number of
capacity blocks 1 1 1 1 1
- --------------------------------------------------------------------------------------------------------
On-line Date 2002 2003 2003 2003 2002
- --------------------------------------------------------------------------------------------------------
Summer
Capacity (MW) 90 90 450 270 540
- --------------------------------------------------------------------------------------------------------
Turndown (%) -- -- -- -- --
- --------------------------------------------------------------------------------------------------------
Fixed O&M
(1998$/kW/yr) 9.8 9.8 9.8 9.8 9.8
- --------------------------------------------------------------------------------------------------------
Heat Rate
(Btu/kWh) - 9,600 9,600 9,600 9,600 9,600
Full Load
- --------------------------------------------------------------------------------------------------------
Primary Fuel Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas
- --------------------------------------------------------------------------------------------------------
Delivered Fuel
Price
(1998$/MMBtu)
2000 5.38 5.52 5.13
2005 3.07 3.21 2.84
2010 3.21 3.38 2.94
2020 3.43 3.67 2.74
- --------------------------------------------------------------------------------------------------------
SO(2) Rate
(lbs/MMBtu) 0.0 0.0 0.0 0.0 0.0
- --------------------------------------------------------------------------------------------------------
NO(x) Rate
(lbs/MMBtu) 0.02 0.02 0.02 0.02 0.02
- --------------------------------------------------------------------------------------------------------
Availability (%) 97.0 97.0 97.0 97.0 97.0
- --------------------------------------------------------------------------------------------------------
In addition to the peaking capacity directly analyzed, PPL owns roughly
275 MW of peaking capacity in PJM. These additional units are available for
dispatch but are expected to only be called to service in super peak periods.
The plants are expected to maintain value over time to serve peak markets. As
such, the ICF portfolio value estimate would be higher if the units were
included in the analysis.
- --------------------------------------------------------------------------------
170 [LOGO] ICF CONSULTING
CHAPTER SEVEN
DETAILED MARKET PRICE AND FLEET OPERATING REVENUE RESULTS
- --------------------------------------------------------------------------------
This chapter discusses in detail the expected earnings of the PPL fleet as
well as the market price results for the individual regions.
ICF has evaluated three specific market cases in order to present a range
of results both for market prices and for the GenCo dispatch performance. The
first case, the Base Case, represents the expected market price that would occur
as a result of all input conditions achieving their expected value under normal
market conditions. This case represents a reasonable, yet conservative, price
expectation for long-term average conditions.
The Low Case represents the downside potential that results from an
overall downside representation of several key input parameters. The Low Case
captures an 80-90 percent confidence interval. The High Fuel Case addresses
uncertainty in the natural gas and oil prices by analyzing the effects of higher
than Base Case fuel prices. Unlike the Low Case, the High Case does not capture
the full upside potential, but focuses only on a single probable event.
Regional Energy and Capacity Prices - Base Case
PJM West Power Price
Strong prices are expected to prevail in PJM on average for the length of
the study. That is, PPL units that perform well currently (coal and nuclear,
especially) are expected to continue to perform well in this study. This is
reflected in our forecast of firm (unit contingent bundled) all-hours
electricity prices steadily in the $30 - 40/MWh range throughout the study
(1998$). These prices are in real dollars, and hence, increase steadily with
general economy-wide inflation reaching $54/MWh by 2020 assuming a 2.5 percent
annual inflation rate.
- --------------------------------------------------------------------------------
171 [LOGO] ICF CONSULTING
Exhibit 7-1
Base Case Western PJM Power Price Summary-Real 1998$
- -------------------------------------------------------------------------------------------------------------
All Hours Marginal Annual Capacity Firm Power
Year Electrical Energy Price ($/kW/yr) Price(1) ($/MWh) New Build Mix(2)
Prices ($/MWh)
- -------------------------------------------------------------------------------------------------------------
2001 28.1 101 39.6 No Unplanned Builds
- -------------------------------------------------------------------------------------------------------------
2002 25.8 129 40.5 No Unplanned Builds
- -------------------------------------------------------------------------------------------------------------
2003 24.4 58 31.0 No Unplanned Builds
- -------------------------------------------------------------------------------------------------------------
2005 23.8 65 31.2 Cogen
- -------------------------------------------------------------------------------------------------------------
2010 26.3 64 33.6 CC, CT, Cogen
- -------------------------------------------------------------------------------------------------------------
2015 25.5 61 32.5 CC, CT, Cogen
- -------------------------------------------------------------------------------------------------------------
2020 25.1 57 31.6 CC, CT, Cogen
- -------------------------------------------------------------------------------------------------------------
Levelized
Price 25.4 74 33.8 --
2001-2020(3)
- -------------------------------------------------------------------------------------------------------------
Note: Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region. PJM East, South, & West are included.
3 Utilizes an 11.2 percent real discount rate.
Two components of prices are shown. The first component is the competitive
electrical energy prices which equal the short-run variable costs of the
marginal, i.e., last unit in the grid to be dispatched. The second component is
the capacity price. This represents the price available in the separate capacity
market plus premiums above electrical energy prices associated with a potential
shortage of MW during peak hours. Thus, PPL PJM units can receive the capacity
payment either through the PJM capacity market mechanism or price spikes.
The electrical energy price in western PJM is flat to declining in real
terms through 2005. This reflects two offsetting trends. On the downside, new,
more efficient combined cycles and lower natural gas prices (relative to current
and 2001 prices) depress electricity prices. On the upside, higher electricity
demand growth decreases the amount of time existing low variable cost units set
the wholesale electricity price. Between 2005 and 2010, electrical energy prices
rise as natural gas prices and demand rise. Thereafter, gas price and demand
growth increases are mitigated by the availability new, more efficient combined
cycles.
The capacity price reflects an imbalance in the markets through 2002,
small changes in demand or capacity from the normal or expected levels could
significantly alter the 2002 value in particular given the high degree of
uncertainty and volatility associated with it. Thereafter, capacity prices
return to equilibrium levels associated with the investment and operating costs
of newly developed units which are expected to decline over time.
The firm power price represents a combination of the energy and capacity
price. It is exaggerated in the very near-term, declines through 2003 with
decreasing gas costs, slowly rises
- --------------------------------------------------------------------------------
172 [LOGO] ICF CONSULTING
through 2010, reflecting tighter capacity markets and increasing fuel costs, and
again declines through 2020, reflecting the decreasing costs of new units.
Exhibit 7-2
Base Case Western PJM Power Price Summary-Nominal Dollars
- --------------------------------------------------------------------------------
All Hours Marginal Annual Capacity Firm Power Price(1)
Year Energy Prices Price ($/kW/yr) ($/MWh)
($/MWh)
- --------------------------------------------------------------------------------
2001 29.8 107 42.0
- --------------------------------------------------------------------------------
2002 28.0 140 44.0
- --------------------------------------------------------------------------------
2003 27.2 65 34.6
- --------------------------------------------------------------------------------
2005 27.9 76 36.6
- --------------------------------------------------------------------------------
2010 34.8 85 44.5
- --------------------------------------------------------------------------------
2015 38.3 92 48.7
- --------------------------------------------------------------------------------
2020 42.6 97 53.6
- --------------------------------------------------------------------------------
Levelized
Price(2) 31.2 90 41.5
2001 - 2020
- --------------------------------------------------------------------------------
Note: Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices. Nominal dollars are calculated using actual inflation of 1.5
percent between 1998 and 1999 and 2.5 percent annually thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent.
2 Utilizes an 11.2 percent real discount rate or 13.7 percent nominal
discount rate.
In nominal terms, firm power prices are slightly inflated in the near term
and therefore fall through 2005, similar to the real price trend. Thereafter
prices increase in nominal terms as the inflation rate exceeds the growth rate
in the real prices.
NEPOOL Power Price
The NEPOOL market has historically experienced high energy prices due to
the high costs of fuel and abundance of existing steam units. Given the
potential heat rate arbitrage possibilities of new units against existing units,
a significant number of developers have announced capacity additions in the
NEPOOL market. As such, NEPOOL was one of the first markets to see capacity
additions under deregulation. Approximately 6.7 GW of new capacity was firmly
committed for development between 1999 and 2003. The effect of the new builds is
to stabilize the market prices within NEPOOL and reduce the potential for
periods of extreme price spikes and/or high ICAP capacity prices.
- --------------------------------------------------------------------------------
173 [LOGO] ICF CONSULTING
Exhibit 7-3
Base Case NEPOOL Power Price Summary-Real 1998$
- ------------------------------------------------------------------------------------------------
All Hours Annual Firm Power
Year Marginal Energy Capacity Price Price(1) New Build Mix(2)
Prices ($/MWh) ($/kW/yr) ($/MWh)
- ------------------------------------------------------------------------------------------------
2001 42.8 148 59.7 No Unplanned Builds
- ------------------------------------------------------------------------------------------------
2002 33.4 133 48.6 No Unplanned Builds
- ------------------------------------------------------------------------------------------------
2003 30.2 60 37.1 No Unplanned Builds
- ------------------------------------------------------------------------------------------------
2005 28.4 62 35.5 No Unplanned Builds
- ------------------------------------------------------------------------------------------------
2010 29.0 76 37.7 CC, CT, Cogen
- ------------------------------------------------------------------------------------------------
2015 28.6 69 36.5 CC, CT, Cogen
- ------------------------------------------------------------------------------------------------
2020 27.4 66 34.9 CC, CT, Cogen
- ------------------------------------------------------------------------------------------------
Levelized Price(3)
2001-2020 30.9 83 40.4 --
- ------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Utilizes an 11.2 percent real discount rate.
Exhibit 7-4
Base Case NEPOOL Power Price Summary-Nominal Dollars
- --------------------------------------------------------------------------------
All Hours Marginal Annual Capacity Firm Power
Year Energy Prices ($/MWh) Price ($/kW/yr) Price(1) ($/MWh)
- --------------------------------------------------------------------------------
2001 45.5 157 63.4
- --------------------------------------------------------------------------------
2002 36.4 145 52.9
- --------------------------------------------------------------------------------
2003 33.7 67 41.4
- --------------------------------------------------------------------------------
2005 33.3 73 41.6
- --------------------------------------------------------------------------------
2010 38.5 101 50.0
- --------------------------------------------------------------------------------
2015 42.9 104 54.7
- --------------------------------------------------------------------------------
2020 46.5 112 59.3
- --------------------------------------------------------------------------------
Levelized
Price(2) 38.0 102 49.6
2001 - 2020
- --------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Utilizes an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
In our forecast, the NEPOOL energy price is driven mainly by the price of
gas and the efficiency of new units that come online. In the near-term, energy
prices are high and drop
- --------------------------------------------------------------------------------
174 [LOGO] ICF CONSULTING
quickly as real gas prices also fall. Beyond 2005, increases in real gas prices
drive energy prices back up in real terms, but beyond that, advancements in
technology reflected through heat rate improvements, counteract the effect of
increasing real gas prices.
Likewise, capacity prices start at relatively high levels before dropping
to equilibrium levels in the long-term. The near-term capacity price reflects
the ability of NEPOOL to export excess capacity to neighboring downstate New
York. This price is determined by the cost of construction in the neighboring
market and is in turn high because developers bringing capacity on anticipate
lower revenues in 2003 and need to concentrate recovery in the up front years.
Montana Power Price
Exhibit 7-5
Base Case Montana Power Price Summary - Real 1998$
- ---------------------------------------------------------------------------------------------------
All Hours
Marginal Annual Capacity Firm Power Price(1)
Year Electrical Energy Price ($/kW/yr) ($/MWh) New Build Mix(2)
Prices ($/MWh)
- ---------------------------------------------------------------------------------------------------
No Unplanned
2001 50.4 102 62.1 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2002 31.5 152 48.8 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2003 28.7 59 35.4 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2005 22.8 58 29.4 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2010 23.9 61 30.9 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2015 21.0 74 29.4 Builds
- ---------------------------------------------------------------------------------------------------
No Unplanned
2020 17.1 70 25.1 Builds
- ---------------------------------------------------------------------------------------------------
Levelized Prices
2001 - 2020(3) 27.3 75 35.9 --
- ---------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Using an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
175 [LOGO] ICF CONSULTING
Exhibit 7-6
Base Case Montana Power Price Summary - Nominal Dollars
- ---------------------------------------------------------------------------------------
All Hours Marginal Annual Capacity Price Firm Power Price(1)
Year Electrical Energy Prices ($/kW/yr) ($/MWh)
($/MWh)
- ---------------------------------------------------------------------------------------
2001 53.5 108 65.9
- ---------------------------------------------------------------------------------------
2002 34.2 165 53.1
- ---------------------------------------------------------------------------------------
2003 32.0 66 39.5
- ---------------------------------------------------------------------------------------
2005 26.7 68 34.4
- ---------------------------------------------------------------------------------------
2010 31.7 81 40.9
- ---------------------------------------------------------------------------------------
2015 31.5 111 44.2
- ---------------------------------------------------------------------------------------
2020 29.0 119 42.6
- ---------------------------------------------------------------------------------------
Levelized
Prices 33.5 92 44.0
2001 - 2020(2)
- ---------------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor. The total amount of builds is based on the reserve
margin criteria for the region.
2 Using an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
The Montana real energy price decreases in the near- to mid-term
reflecting the real drop in gas prices. Prices increase between 2005 and 2010
before a declining through 2020. Through the mid-term of the forecast,
electrical energy prices closely parallel the gas price trend. In the mid- to
long-term, the effect of increased efficiency at the new units counteracts the
impact of increasing gas prices and electrical energy prices are decreasing.
Between 2015 and 2020, gas prices along with increasing efficiency at new units,
real gas prices decrease driving energy prices down even further.
Real capacity prices begin at $102/kW/yr in 2001 with a modest increase in
2002. The value of capacity in Montana reflects the value of trades with
neighboring regions. Montana is both an importer and exporter of capacity with
strong transmission ties to neighboring Northwest Power Pool markets.
- --------------------------------------------------------------------------------
176 [LOGO] ICF CONSULTING
AZNM Power Price
Exhibit 7-7
Base Case AZNM Power Price Summary - Real 1998$
- -------------------------------------------------------------------------------------------------
All Hours
Marginal Annual Capacity Firm Power Price(1)
Year Electrical Energy Price ($/kW/yr) ($/MWh) New Build Mix(2)
Prices ($/MWh)
- -------------------------------------------------------------------------------------------------
No Unplanned
2001 47.0 124 61.1 Builds
- -------------------------------------------------------------------------------------------------
No Unplanned
2002 32.8 187 54.1 Builds
- -------------------------------------------------------------------------------------------------
No Unplanned
2003 29.1 73 37.4 Builds
- -------------------------------------------------------------------------------------------------
No Unplanned
2005 22.9 72 31.1 Builds
- -------------------------------------------------------------------------------------------------
2010 23.1 83 32.5 CT
- -------------------------------------------------------------------------------------------------
2015 21.9 79 30.9 CT
- -------------------------------------------------------------------------------------------------
2020 20.0 73 28.3 CC, CT
- -------------------------------------------------------------------------------------------------
Levelized Prices
2001 - 2020(3) 27.2 92 37.7 --
- -------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Using an 11.2 percent real discount rate.
Exhibit 7-8
Base Case AZNM Power Price Summary - Nominal Dollars
- ------------------------------------------------------------------------------------
All Hours Marginal
Electrical Energy Annual Capacity Price Firm Power Price(1)
Year Prices ($/MWh) ($/kW/yr) ($/MWh)
- ------------------------------------------------------------------------------------
2001 49.9 132 64.9
- ------------------------------------------------------------------------------------
2002 35.7 204 58.9
- ------------------------------------------------------------------------------------
2003 32.4 81 41.7
- ------------------------------------------------------------------------------------
2005 26.8 84 36.5
- ------------------------------------------------------------------------------------
2010 30.6 110 43.2
- ------------------------------------------------------------------------------------
2015 32.9 119 46.4
- ------------------------------------------------------------------------------------
2020 33.9 124 48.1
- ------------------------------------------------------------------------------------
Levelized Prices
2001-2020(2) 33.9 113 46.4
- ------------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Using an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
- --------------------------------------------------------------------------------
177 [LOGO] ICF CONSULTING
Similar to other regions, the Arizona/New Mexico near-term energy price is
highly influenced by the near-term high natural gas prices. Real and nominal
energy prices decline through 2005 before increasing. Beyond 2010, energy prices
are decreasing in real terms and increasing in nominal terms as the rate of
decline is below the inflation rate.
The capacity markets in Arizona/New Mexico are closely linked to those in
California given the large transmission interconnections and the reliance of
California on external power sources to meet consumer demand. As such, a
substantial excess in the capacity price is expected for the next few years
until sufficient capacity additions can be brought on-line to reliably serve
load. The market prices remain strong thereafter at levels between $70 and
80/kWyr (real 1998$).
PACNW Power Price
Exhibit 7-9
Base Case Pacific Northwest Power Price Summary - Real 1998$
- --------------------------------------------------------------------------------------------------------
All Hours
Year Marginal Annual Capacity Firm Power Price(1) New Build Mix(2)
Electrical Energy Price ($/kW/yr) ($/MWh)
Prices ($/MWh)
- --------------------------------------------------------------------------------------------------------
2001 55.1 124 69.3 No Unplanned
Builds
- --------------------------------------------------------------------------------------------------------
2002 34.9 184 55.9 No Unplanned
Builds
- --------------------------------------------------------------------------------------------------------
2003 31.7 72 39.9 No Unplanned
Builds
- --------------------------------------------------------------------------------------------------------
2005 25.5 71 33.6 Cogen
- --------------------------------------------------------------------------------------------------------
2010 25.1 74 33.5 CC, Cogen
- --------------------------------------------------------------------------------------------------------
2015 21.9 74 30.3 CC, Cogen
- --------------------------------------------------------------------------------------------------------
2020 17.6 71 25.7 CC, Cogen
- --------------------------------------------------------------------------------------------------------
Levelized Prices 29.6 89 39.7 --
2001 - 2020(3)
- --------------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Using an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
178 [LOGO] ICF CONSULTING
Exhibit 7-10
Base Case Pacific Northwest Power Price Summary - Nominal Dollars
- --------------------------------------------------------------------------------------
All Hours Marginal
Electrical Energy Prices Annual Capacity Price Firm Power Price(1)
Year ($/MWh) ($/kW/yr) ($/MWh)
- --------------------------------------------------------------------------------------
2001 58.5 132 73.5
- --------------------------------------------------------------------------------------
2002 37.9 200 60.8
- --------------------------------------------------------------------------------------
2003 35.4 80 44.5
- --------------------------------------------------------------------------------------
2005 29.8 83 39.3
- --------------------------------------------------------------------------------------
2010 33.3 98 44.5
- --------------------------------------------------------------------------------------
2015 32.8 111 45.5
- --------------------------------------------------------------------------------------
2020 29.9 121 43.7
- --------------------------------------------------------------------------------------
Levelized
Prices 36.3 109 48.8
2001-2020(2)
- --------------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Using an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
The Pacific Northwest has historically been one of the lowest cost regions
in the US. Recently, their has been a near shortage situation in the Pacific
Northwest, in part due to the California crisis, in part due to the low hydro
conditions, but also due to the limited capacity expansion that has occurred in
the market. In 2001, not only are inflated fuel prices responsible for extremely
high energy prices, but low hydro conditions are prevailing in the west. The
hydro resource availability has significant impacts on the Northwest given the
large dominance of hydro resources in the generation mix. By 2002, we have
assumed that the market returns to average hydro conditions, as a result, energy
prices fall significantly.
The hydro resource availability also affects the capacity price as the
hydro resources must have adequate water supply to draw from in order to support
peak load periods. The 2001 price reflects that only limited hydro resources
will be available at the summer peak for the WSCC markets.
Overall, the firm power price tends to start at relatively high real
prices but drops in real terms thereafter. In nominal terms, firm prices
decrease fairly significantly in the near term and through 2005. Beyond 2005,
the rate of decline in the real power price is not as strong as the inflation
rate and nominal prices increase or maintain a relatively flat level.
- --------------------------------------------------------------------------------
179 [LOGO] ICF CONSULTING
LILCO Power Price
Exhibit 7-11
Base Case LILCO Power Price Summary - Real 1998$
- -------------------------------------------------------------------------------------------------------------
All Hours
Marginal Annual Capacity Firm Power Price(1)
Year Electrical Energy Price ($/kW/yr) ($/MWh) New Build Mix(2)
Prices ($/MWh)
- -------------------------------------------------------------------------------------------------------------
No Unplanned
2001 46.3 150 63.4 Builds
- -------------------------------------------------------------------------------------------------------------
No Unplanned
2002 41.2 237 68.2 Builds
- -------------------------------------------------------------------------------------------------------------
No Unplanned
2003 37.0 87 46.9 Builds
- -------------------------------------------------------------------------------------------------------------
2005 29.6 83 39.1 Cogen
- -------------------------------------------------------------------------------------------------------------
2010 29.7 68 37.4 Cogen
- -------------------------------------------------------------------------------------------------------------
2015 29.7 62 36.8 Cogen
- -------------------------------------------------------------------------------------------------------------
2020 28.9 59 35.6 Cogen
- -------------------------------------------------------------------------------------------------------------
Levelized Prices
2001 - 2020(3) 33.7 100 45.0 --
- -------------------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Using an 11.2 percent real discount rate.
Exhibit 7-12
Base Case LILCO Power Price Summary - Nominal Dollars
- ------------------------------------------------------------------------------------
All Hours Marginal
Electrical Energy Prices Annual Capacity Price Firm Power Price(1)
Year ($/MWh) ($/kW/yr) ($/MWh)
- ------------------------------------------------------------------------------------
2001 49.1 159 67.3
- ------------------------------------------------------------------------------------
2002 44.8 258 74.2
- ------------------------------------------------------------------------------------
2003 41.2 97 52.3
- ------------------------------------------------------------------------------------
2005 34.7 97 45.8
- ------------------------------------------------------------------------------------
2010 39.4 90 49.6
- ------------------------------------------------------------------------------------
2015 44.6 93 55.2
- ------------------------------------------------------------------------------------
2020 49.0 100 60.4
- ------------------------------------------------------------------------------------
Levelized Prices
2001-2020(2) 41.3 122 55.3
- ------------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Using an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
- --------------------------------------------------------------------------------
180 [LOGO] ICF CONSULTING
PPL is planning to install a generating facility on Long Island.
Currently, this market and it neighbor, New York City, are in danger of facing a
capacity shortage because of it's reliance on internal generating capabilities
and it's relative isolation from other markets. The recent addition of
transmission capacity from NEPOOL to Long Island somewhat helps to alleviate
this situation, but near-term premiums resulting for m limited capacity supply
are expected in 2001 and 2002. The 2001 capacity price reflects premiums
associated with limited resources. Likewise 2002, reflects these premiums. In
addition, the 2002 is higher in real terms as developers are limited in what
type of capacity can be installed in 2002 and expect that additional, lower cost
capacity will be available in 2003. With the units available to come online in
2003, developers must recover more than the annualized costs of their 2002 units
in order to break-even on these units. Given that construction in Long Island is
not anticipated, the LILCo capacity price also reflects transmission charges for
importing available capacity from other markets.
ComEd Power Price
Exhibit 7-13
Base Case ComEd Power Price Summary - Real 1998$
- ----------------------------------------------------------------------------------------------------
All Hours Marginal
Year Electrical Energy Annual Capacity Firm Power New Build Mix(2)
Prices ($/MWh) Price ($/kW/yr) Price(1) ($/MWh)
- ----------------------------------------------------------------------------------------------------
No Unplanned
2001 20.3 99 31.6 Builds
- ----------------------------------------------------------------------------------------------------
No Unplanned
2002 18.8 93 29.4 Builds
- ----------------------------------------------------------------------------------------------------
No Unplanned
2003 17.4 58 24.0 Builds
- ----------------------------------------------------------------------------------------------------
No Unplanned
2005 19.2 67 26.8 Builds
- ----------------------------------------------------------------------------------------------------
2010 22.7 72 30.9 CT, Cogen
- ----------------------------------------------------------------------------------------------------
2015 23.8 67 31.4 CC, CT, Cogen
- ----------------------------------------------------------------------------------------------------
2020 22.6 62 29.7 CC, CT, Cogen
- ----------------------------------------------------------------------------------------------------
Levelized
Prices 20.6 73 28.9 --
2001 - 2020(3)
- ----------------------------------------------------------------------------------------------------
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Unplanned builds resulting from the model are indicated while firmly
planned builds are not shown. Unless specified as firm, the builds
indicated result from the model which optimally selects the build mix to
minimize system costs. The total amount of builds is based on the reserve
margin criteria for the region.
3 Using an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
181 [LOGO] ICF CONSULTING
Exhibit 7-14
Base Case ComEd Power Price Summary - Nominal Dollars
- ----------------------------------------------------------------------------------------------
All Hours Marginal
Year Electrical Energy Prices Annual Capacity Price Firm Power Price(1)
($/MWh) ($/kW/yr) ($/MWh)
- ----------------------------------------------------------------------------------------------
2001 21.5 105 33.5
- ----------------------------------------------------------------------------------------------
2002 20.4 101 32.0
- ----------------------------------------------------------------------------------------------
2003 19.4 65 26.7
- ----------------------------------------------------------------------------------------------
2005 22.5 79 31.4
- ----------------------------------------------------------------------------------------------
2010 30.1 95 41.0
- ----------------------------------------------------------------------------------------------
2015 35.7 101 47.2
- ----------------------------------------------------------------------------------------------
2020 38.3 105 50.4
- ----------------------------------------------------------------------------------------------
Levelized
Prices 25.3 90 35.5
2001-2020(2)
- ----------------------------------------------------------------------------------------------
Note: Nominal dollars are calculated using actual inflation of 1.5 percent
between 1998 and 1999 and a 2.5 percent annual inflation assumption thereafter.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Using an 11.2 percent real discount rate or a 13.7 percent nominal
discount rate.
In 2001, the ComEd market dispatches significant amounts of baseload type
capacity such that the energy price is not extremely impacted by the gas price
given that gas is not often on the margin. The energy price is reflective of
both higher coal and gas prices, but the market does not have as strong a
response to the gas price as do other markets more heavily loaded with gas-fired
units. Over time, ComEd brings on an increasing amount of gas units as load
continued to grow. As such, the energy price trend tends to follow the gas price
trend.
Likewise, strong capacity prices prevail in 2001 and 2002, however, this
price reflects the value of trades across regions within the Midwest rather than
the need for additional capacity in ComEd. Capacity prices fall in the beginning
of the forecast period, dip in 2003 due to a large amount of construction in the
Midwest, and reach equilibrium by 2005. Thereafter, prices are set by the
required cost recovery of new capacity additions above the profits those units
make from dispatch.
Summary of Results - High Fuel Case
The High Fuel Case represents the possibility of gas and oil prices
remaining at currently inflated levels for several years before dropping to an
equilibrium level that is characterized by conservative estimate of exploration
and production costs and of technological advancements. In the near-term, the
price expected for natural gas purchases is between 11 and 18 percent higher
than price expectations for the Base Case. In the long-term, we expect that this
difference will become stronger. Beyond 2005 gas price expectations are at
roughly 29 percent higher annually.
- --------------------------------------------------------------------------------
182 [LOGO] ICF CONSULTING
Exhibit 7-15
High Fuel Case Firm Power Price(1) Summary-Real 1998$/MWh
- ---------------------------------------------------------------------------------------------------------------------
PJM
Year West(2) NEPOOL Montana AZNM PACNW LILCO ComEd
- ---------------------------------------------------------------------------------------------------------------------
2001 39.9 (0.3) 62.0 (2.3) 67.4 (5.3) 65.0 (3.9) 75.1 (5.8) 63.9 (0.6) 32.8 (1.3)
- ---------------------------------------------------------------------------------------------------------------------
2002 44.2 (3.7) 53.2 (4.6) 53.1 (4.3) 58.5 (4.4) 60.6 (4.8) 73.5 (5.3) 37.0 (7.6)
- ---------------------------------------------------------------------------------------------------------------------
2003 33.9 (2.9) 42.0 (4.9) 42.1 (6.7) 44.6 (7.2) 47.3 (7.4) 52.4 (5.5) 25.8 (1.8)
- ---------------------------------------------------------------------------------------------------------------------
2005 34.8 (3.6) 41.9 (6.5) 30.7 (1.3) 34.0 (2.9) 34.5 (0.9) 44.1 (5.1) 29.2 (2.4)
- ---------------------------------------------------------------------------------------------------------------------
2010 35.7 (2.1) 43.1 (5.4) 31.3 (0.4) 33.4 (0.9) 34.5 (1.0) 42.1 (4.6) 34.5 (3.6)
- ---------------------------------------------------------------------------------------------------------------------
2015 36.2 (3.7) 41.6 (5.1) 31.2 (1.8) 33.7 (2.8) 34.2 (3.9) 40.6 (3.8) 36.7 (5.3)
- ---------------------------------------------------------------------------------------------------------------------
2020 35.4 (3.8) 39.6 (4.7) 29.4 (4.3) 31.0 (2.6) 32.2 (6.4) 38.9 (3.3) 34.5 (4.8)
- ---------------------------------------------------------------------------------------------------------------------
Levelized
Price 36.6 (2.8) 45.5 (5.1) 39.1 (3.2) 41.4 (3.6) 43.6 (3.9) 49.3 (4.3) 32.4 (3.5)
2001-
2020(3)
- ---------------------------------------------------------------------------------------------------------------------
Note: ( ) represents differential from Base Case.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices;
3 Utilizes an 11.2 percent real discount rate.
Exhibit 7-16
High Fuel Case Firm Power Price(1) Summary-Nominal $/MWh
- ---------------------------------------------------------------------------------------------------------------------
Year PJM West(2) NEPOOL Montana AZNM PACNW LILCO ComEd
- ---------------------------------------------------------------------------------------------------------------------
2001 42.4 (0.3) 65.9 (2.5) 71.6 (5.7) 69.0 (4.1) 79.7 (6.2) 67.9 (0.6) 34.9 (1.4)
- ---------------------------------------------------------------------------------------------------------------------
2002 48.1 (4.0) 57.9 (5.0) 57.8 (4.7) 63.7 (4.7) 66.0 (5.2) 80.0 (5.8) 40.2 (8.3)
- ---------------------------------------------------------------------------------------------------------------------
2003 37.9 (3.3) 46.9 (5.5) 47.0 (7.5) 49.7 (8.0) 52.8 (8.3) 58.5 (6.2) 28.8 (2.0)
- ---------------------------------------------------------------------------------------------------------------------
2005 40.8 (4.2) 49.1 (7.6) 36.0 (1.6) 39.8 (3.3) 40.4 (1.1) 51.7 (5.9) 34.3 (2.8)
- ---------------------------------------------------------------------------------------------------------------------
2010 47.3 (2.8) 57.1 (7.1) 41.5 (0.6) 44.3 (1.2) 45.8 (1.3) 55.8 (6.2) 45.7 (4.7)
- ---------------------------------------------------------------------------------------------------------------------
2015 54.3 (5.6) 62.4 (7.7) 46.8 (2.7) 50.6 (4.2) 51.3 (5.8) 60.9 (5.7) 55.1 (7.9)
- ---------------------------------------------------------------------------------------------------------------------
2020 60.0 (6.4) 67.3 (8.0) 49.9 (7.3) 52.6 (4.5) 54.6 (10.9) 66.0 (5.6) 58.5 (8.1)
- ---------------------------------------------------------------------------------------------------------------------
Levelized
Price 45.0 (3.5) 55.9 (8.2) 48.0 (4.0) 50.8 (4.5) 53.6 (4.8) 60.6 (5.3) 39.8 (4.3)
2001-
2020(3)
- ---------------------------------------------------------------------------------------------------------------------
Note: ( ) represents differential from Base Case.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices;
3 Utililizes an 13.7 percent nominal discount rate.
- --------------------------------------------------------------------------------
183 [LOGO] ICF CONSULTING
PJM West Power Price
The real electrical energy price in western PJM is increasing through 2003
before declining through 2005. The trend in gas prices is captured here. That
is, through 2003, high gas prices dominate the energy forecast. Beyond this
point, although real gas prices remain strong, they decline to lower levels.
Combined with this is the addition of new more efficient units to the total PJM
supply mix resulting in fewer exports from PJM West. Between 2005 and 2015,
builds are very limited in PJM West resulting in high sub-regional energy
prices. After this, as new units are constructed within PJM West, real energy
prices again decline.
The High Fuel Case capacity prices are only impacted slightly due to small
differences in energy earnings of the new units regionally. This holds
especially true in PJM West where no unplanned units are expected to be
constructed in the very near-term. As such, the overall trend in firm power
prices is dominated by the energy price effect. The total change from the Base
Case is reflected in the levelized annual real firm power price which is 8
percent above initial levels.
NEPOOL Power Price
The NEPOOL market has historically had a fairly high dependence on oil and
gas units for generation. As such, the impact of gas and oil prices on the
NEPOOL power price is higher than on the PJM West power price. In 2001, the real
firm power price increases by roughly 4 percent above Base Case levels. In
contrast, roughly an 1 percent increase in power prices in PJM West resulted in
2001.
Over time, the impact of the higher fuel prices is felt to a greater
extent. The higher fuel prices effects the optimal mix of new builds, although
it does not effect the total amount of capacity required. Given that many of the
new builds can not earn the same energy premiums under the higher gas prices,
the capacity price also increases as a means to compensate these new units for
their carrying and investment costs. The overall impact on the NEPOOL market of
higher near- and long-term fuel oil and natural gas prices is evident in the
change in the levelized annual firm power price which increases roughly $5/MWh
(real 1998$) or 11 percent.
Montana Power Price
Over time, the energy markets continue to be largely impacted by the
change in fuel prices. However, capacity prices tend to fall somewhat. The fall
in capacity price results from the increased amount of combined cycles and
baseload coal units. Under the high gas prices, coal units, even at their high
capital costs, are attractive in the Montana market as they compete against
significantly higher cost gas fired units on the margin. The combined cycles and
coal earn higher energy margins than in the Base Case, and hence, require less
capital recovery through the capacity price. Unlike the Eastern markets, the
change in the Montana market price is not generally increasing over time, but
tends to fluctuate. In percentage terms, the Montana price increases by between
1 and 16 percent through the forecast horizon.
Arizona/New Mexico Power Price
In most years, the Arizona/New Mexico power price is only moderately
impacted by the change in fuel prices. The strongest impact is felt in 2003 when
the gas price differential is at it's
- --------------------------------------------------------------------------------
184 [LOGO] ICF CONSULTING
near-term greatest from the Base Case. Beyond 2003, the firm power price by
roughly 8 percent in the remaining years as a result of the higher gas and oil
prices.
Pacific Northwest Power Price
The impact of higher gas prices is felt most in the out years in the
Pacific Northwest. In 2020, the firm power price increases by 20 percent as a
result of the long-term effect of the higher resource prices. The some extent,
the impact is muted in the closer years as new coal units are constructed. With
the continued high gas prices, coal units are extremely attractive in the
market. By 2005, new coal units are available in the marketplace. However, in
many hours, the market price is determined by gas units on the margin, wither
within the Pacific Northwest, or in regions being exported to. Since gas units
continue to dominate the margin, coal units earn significant energy profits. In
turn, capacity prices drop since much of the recovery is provided through energy
profits. As a result of the change in the new build mix to include coal units,
the power price is not impacted to the same extent as it would have been in the
absence of the coal options. By 2020, gas prices and energy prices fall to the
point where coal is no longer attractive as a new resource. As such, the gas
price becomes very dominant in determining the firm power price and the impact
of the higher prices is at it's strongest.
LILCO Power Price
On average, the LILCO region sees a 9 percent increase in the power price
as a result of higher gas and oil prices. In comparison, the gas price changes
by an average of 21 percent in the same period. As in the other regions, the
power price elasticity with respect to changes in the fuel prices is limited by
the ability of the markets to react through shifts in transmission and the build
mix.
ComEd Power Price
In general, the increase in gas prices impact the energy prices in the
ComEd region. However, in 2002, the capacity value shows a significant increase
as new required capacity must recover their capital investment costs through the
capacity payment. A premium is demanded by these units given the limited amount
of capacity available to be added to the grid in time for the 2002 summer
period. Since the only units that can be added are high variable costs units,
they earn little to no energy margin and therefore require a higher capacity
payment. The expectation of lower costs units being available in the future
years also serves increase the 2002 capacity price since the annual price may
not be high enough to compensate the 2002 units' investment costs at a level
equal to the annualized capital cost.
- --------------------------------------------------------------------------------
185 [LOGO] ICF CONSULTING
Summary of Results -- Low Case
The Low Case represents the downside potential that results from an
overall downside representation of several key input parameters. The Low Case
captures an 80-90 percent confidence interval. The High Fuel Case addresses
uncertainty in the natural gas and oil prices by analyzing the effects of higher
than Base Case fuel prices. Unlike the Low Case, the High Case does not capture
the full upside potential, but focuses only on a single probable event.
Exhibit 7-17
Low Case Firm Power Price(1) Summary-Real 1998$/MWh
- -------------------------------------------------------------------------------------------------------------------------------
Year PJM West(2) NEPOOL Montana AZNM PACNW LILCO ComEd
- -------------------------------------------------------------------------------------------------------------------------------
2001 39.0 (-0.6) 57.8 (-1.9) 59.4 (-2.7) 56.1 (-5.0) 66.7 (-2.8) 62.3 (-1.1) 32.0 (0.4)
- -------------------------------------------------------------------------------------------------------------------------------
2002 27.4 (-13.1) 33.8 (-14.8) 33.9 (-14.9) 36.7 (-17.5) 38.3 (-19.1) 43.0 (-25.2) 21.6 (-7.7)
- -------------------------------------------------------------------------------------------------------------------------------
2003 27.4 (-3.6) 31.9 (-5.1) 31.0 (-4.4) 33.1 (-4.3) 35.1 (-5.3) 40.1 (-6.8) 22.2 (-1.8)
- -------------------------------------------------------------------------------------------------------------------------------
2005 27.8 (-3.4) 30.5 (-5.0) 25.3 (-4.1) 27.1 (-4.1) 29.0 (-5.4) 34.6 (-4.4) 23.8 (-3.0)
- -------------------------------------------------------------------------------------------------------------------------------
2010 27.2 (-6.4) 31.0 (-6.7) 23.3 (-7.6) 24.8 (-7.7) 25.4 (-10.7) 30.9 (-6.6) 25.5 (-5.5)
- -------------------------------------------------------------------------------------------------------------------------------
2015 27.0 (-5.5) 30.7 (-5.8) 21.6 (-7.8) 24.1 (-6.9) 23.6 (-10.1) 31.2 (-5.6) 26.1 (-5.3)
- -------------------------------------------------------------------------------------------------------------------------------
2020 26.4 (-5.1) 29.5 (-5.4) 20.0 (-5.1) 22.3 (-6.1) 20.0 (-9.7) 30.3 (-5.3) 24.4 (-5.3)
- -------------------------------------------------------------------------------------------------------------------------------
Level-
ized
Price 28.7 (-5.1) 34.2 (-6.2) 29.4 (-6.4) 30.9 (-6.9) 32.9 (-8.4) 37.8 (-7.2) 25.0 (-3.9)
2001-
2020(3)
- -------------------------------------------------------------------------------------------------------------------------------
Note: ( ) represents differential from Base Case.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices;
3 Utilizes an 11.2 percent real discount rate.
- --------------------------------------------------------------------------------
186 [LOGO] ICF CONSULTING
Exhibit 7-18
Low Case Firm Power Price(1) Summary-Nominal $/MWh
- -------------------------------------------------------------------------------------------------------------------------------
Year PJM West(2) NEPOOL Montana AZNM PACNW LILCO ComEd
- -------------------------------------------------------------------------------------------------------------------------------
2001 41.4 (-0.6) 61.4 (-2.0) 63.1 (-2.8) 59.6 (-5.3) 70.8 (-2.8) 66.1 (-1.2) 34.0 (0.5)
- -------------------------------------------------------------------------------------------------------------------------------
2002 29.8 (-14.3) 36.8 (-16.1) 36.9 (-16.3) 39.9 (-19.0) 41.7 (-19.1) 46.8 (-27.5) 23.5 (-8.4)
- -------------------------------------------------------------------------------------------------------------------------------
2003 30.5 (-4.1) 35.6 (-5.7) 34.6 (-4.8) 36.9 (-4.8) 39.2 (-5.3) 44.8 (-7.5) 24.8 (-2.0)
- -------------------------------------------------------------------------------------------------------------------------------
2005 32.6 (-4.0) 35.7 (-5.8) 29.6 (-4.8) 31.7 (-4.8) 34.0 (-5.4) 40.6 (-5.2) 27.9 (-3.5)
- -------------------------------------------------------------------------------------------------------------------------------
2010 36.1 (-8.4) 41.1 (-8.9) 30.9 (-10.0) 32.9 (-10.2) 33.7 (-10.7) 40.9 (-8.7) 33.8 (-7.2)
- -------------------------------------------------------------------------------------------------------------------------------
2015 40.6 (-8.2) 46.1 (-8.7) 32.4 (-11.7) 36.1 (-10.3) 35.4 (-10.1) 46.8 (-8.5) 39.2 (-7.9)
- -------------------------------------------------------------------------------------------------------------------------------
2020 44.9 (-8.7) 50.1 (-9.2) 34.0 (-8.7) 37.8 (-10.3) 34.0 (-9.7) 51.4 (-9.0) 41.4 (-8.9)
- -------------------------------------------------------------------------------------------------------------------------------
Level-
ized
Price 35.2 (-6.3) 42.0 (-7.6) 36.1 (-7.9) 37.9 (-8.4) 40.4 (-8.4) 46.5 (-8.8) 30.7 (-4.8)
2001-
2020(3)
- -------------------------------------------------------------------------------------------------------------------------------
Note: ( ) represents differential from Base Case.
1 Calculated as the all hour energy price plus the capacity price at 100
percent load factor.
2 Values shown for PJM West only and may differ somewhat from PJM East or
PJM South prices;
3 Utilizes an 13.7 percent nominal discount rate.
As mentioned earlier, the Low Case has a higher expected deviation from
the Base Case than does the High Fuel Case. Overall, the market prices are
impacted between 16 and 22 percent on a levelized average basis as compared to a
9 percent change in the High Fuel Case. In general, the strongest impact is felt
in the WSCC regions while the Midwest regions feel the least impact. To some
extent, the relative degree of change is due to the higher prices experienced in
the western regions in the Base Case. At these higher price levels, the regions
are subject to a greater variation before price floors are reached.
- --------------------------------------------------------------------------------
187 [LOGO] ICF CONSULTING
Portfolio Revenue and Dispatch Assessment
The PPL fleet is concentrated in PJM with almost 70 percent of the total
existing and under construction capacity; revenue contribution of the PJM assets
to total revenues in the Base Case equivalent to the capacity contribution. The
NPVs presented represent expected values from dispatch as modeled by ICF. These
values do not include a full representation of fixed costs, nor do they include
tax or debt payments. As such, the values presented herein may differ somewhat
from a full engineering assessment of the units, however, the magnitude and
relationship between the units should remain consistent.
Exhibit 7-19
PPL Generating Stations Regional Revenue and Capacity Concentration
- -----------------------------------------------------------------------------
NPV (Millions of Dollars (1998$)(2),(3)
Region Capacity -------------------------------------------------
(MW)(1) Base High Fuel Low Case
- -----------------------------------------------------------------------------
PJM 9,048 7,950 9,044 5,599
- -----------------------------------------------------------------------------
NEPOOL 323 272 296 208
- -----------------------------------------------------------------------------
Montana 1,242 2,062 2,272 1,601
- -----------------------------------------------------------------------------
Arizona 710 471 442 352
- -----------------------------------------------------------------------------
PacNW 1,200 563 514 498
- -----------------------------------------------------------------------------
LILCO 270 128 127 105
- -----------------------------------------------------------------------------
ComEd 540 263 278 205
- -----------------------------------------------------------------------------
Total 13,334 11,710 12,973 8,568
- -----------------------------------------------------------------------------
1 2005 PPL owned capacity is shown.
2 NPV calculated using an 11.2 percent real discount rate.
3 Does not include taxes, debt, some cost items such as new capital
additions. Includes revenue, short run variable costs and FERC Form 1
non-fuel O&M.
On a per kilowatt basis, the PJM units contribute on average about $880
thousand dollars to operating revenues in the Base Case. Relative to an average
unit, this is a large amount per MW. For example, a MW combined cycle in PJM
would typically contribute around $600/kW. The Montana units have a very high
revenue contribution at nearly $1,700/kW. The Montana units represent highly
valued baseload units. Nearly 80 percent of the total fleet capacity and
revenues are within PJM and Montana, these units dispatch very well throughout
the forecast time horizon.
- --------------------------------------------------------------------------------
188 [LOGO] ICF CONSULTING
Exhibit 7-20
PPL Generating Stations Regional Revenue and Capacity Concentration
[GRAPH]
PJM Assessment
The PJM fleet is largely baseload capacity with high earning potential.
Expected values from dispatch are presented in Exhibit 7-21.
- --------------------------------------------------------------------------------
189 [LOGO] ICF CONSULTING
Exhibit 7-21
PPL PJM Generating Stations - Operating Revenues - Base, Low and High Case
- --------------------------------------------------------------------------------------------------------
NPV (1998$/kW)
Plant Capacity -----------------------------------------
Base High Low
- --------------------------------------------------------------------------------------------------------
Brunner Island 1 & 2 713 951 1,130 640
- --------------------------------------------------------------------------------------------------------
Brunner Island 3 735 1,063 1,231 740
- --------------------------------------------------------------------------------------------------------
Conemaugh Coal 276 1,170 1,347 842
- --------------------------------------------------------------------------------------------------------
Keystone 1(1) 105 1,126 1,299 798
- --------------------------------------------------------------------------------------------------------
Keystone 2(1) 105 1,127 1,299 799
- --------------------------------------------------------------------------------------------------------
Martins Creek Coal 280 803 956 528
- --------------------------------------------------------------------------------------------------------
Montour Coal 1,518 1,078 1,240 761
- --------------------------------------------------------------------------------------------------------
Coal Capacity Weighted Avg 3,733 1,040 1,207 724
- --------------------------------------------------------------------------------------------------------
Susquehanna(2) 2,057 1,054 1,231 725
- --------------------------------------------------------------------------------------------------------
Nuclear Capacity Avg 2,057 1,054 1,231 725
- --------------------------------------------------------------------------------------------------------
Holtwood Hydro 102 1,462 1,634 1,154
- --------------------------------------------------------------------------------------------------------
Safe Harbor 139 853 934 631
- --------------------------------------------------------------------------------------------------------
Wallenpaupack 44 719 786 513
- --------------------------------------------------------------------------------------------------------
Hydro Capacity Weighted Avg 285 1,050 1,162 800
- --------------------------------------------------------------------------------------------------------
Lower Mount Bethel 520 557 567 401
- --------------------------------------------------------------------------------------------------------
CC Weighted Avg 520 557 567 401
- --------------------------------------------------------------------------------------------------------
Brunner Island Diesels 9 685 709 527
- --------------------------------------------------------------------------------------------------------
Martins Creek CT 72 581 606 423
- --------------------------------------------------------------------------------------------------------
Mount Bethel Duct 82 468 643 309
- --------------------------------------------------------------------------------------------------------
CT Capacity Weighted Avg 81 530 630 371
- --------------------------------------------------------------------------------------------------------
Martins Creek Steam (gas) 900 633 661 474
- --------------------------------------------------------------------------------------------------------
Martins Creek Steam (oil) 760 536 568 369
- --------------------------------------------------------------------------------------------------------
Oil/Gas Steam Capacity Weighted Avg 1,660 589 618 426
- --------------------------------------------------------------------------------------------------------
Eden 90 504 530 350
- --------------------------------------------------------------------------------------------------------
Upper Hanover 90 399 407 326
- --------------------------------------------------------------------------------------------------------
West Earl 450 397 405 327
- --------------------------------------------------------------------------------------------------------
LM6000 Capacity Weighted Avg 630 413 423 330
- --------------------------------------------------------------------------------------------------------
Total Capacity Weighted Avg 9,048 879 1,000 619
- --------------------------------------------------------------------------------------------------------
1 PPL owns 16.25 percent of the total 850 MW of Conemaugh and 12.4 percent
of the total 850 MW of Keystone.
2 PPL owns 90 percent of the total 2,184 MW at Susquehanna.
Note: Does not include taxes, debt, or some cost items such as new capital
additions. Includes revenue, short run variable costs and FERC Form 1 O&M.
As seen in Exhibit 7-22, the capacity factors for the baseload units are
relatively high and steady over time. In addition to the existing baseload
units, the Lower Mount Bethel combined cycle is expected to be operational by
2003. This unit is expected to operate near baseload levels.
The remaining PPL PJM units operate as peakers and earn their main
revenues from the capacity markets. These revenues may be from a separate
capacity market, energy price spikes or both.
- --------------------------------------------------------------------------------
190 [LOGO] ICF CONSULTING
Exhibit 7-22
PPL PJM Generating Stations Projected Annual Capacity Factor (%) - Base Case
- --------------------------------------------------------------------------------
Facility 2001 2003 2005 2010 2015 2020
- --------------------------------------------------------------------------------
Brunner Island 1 & 2 84% 80% 84% 84% 63% 61%
- --------------------------------------------------------------------------------
Brunner Island 3 84% 84% 84% 84% 84% 84%
- --------------------------------------------------------------------------------
Conemaugh Coal 1&2(1) 87% 87% 87% 87% 87% 87%
- --------------------------------------------------------------------------------
Keystone 1(1) 87% 87% 87% 87% 87% 87%
- --------------------------------------------------------------------------------
Keystone 2(1) 87% 87% 87% 87% 87% 87%
- --------------------------------------------------------------------------------
Martins Creek Coal 65% 57% 66% 63% 42% 55%
- --------------------------------------------------------------------------------
Montour Coal 81% 81% 81% 81% 81% 81%
- --------------------------------------------------------------------------------
Coal Capacity Weighted Avg 82% 80% 82% 81% 76% 76%
- --------------------------------------------------------------------------------
Susquehanna 88% 88% 88% 88% 88% 88%
- --------------------------------------------------------------------------------
Nuclear Capacity Weighted Avg 88% 88% 88% 88% 88% 88%
- --------------------------------------------------------------------------------
Holtwood Hydro 64% 64% 64% 64% 64% 64%
- --------------------------------------------------------------------------------
Safe Harbor 29% 29% 29% 29% 29% 29%
- --------------------------------------------------------------------------------
Wallenpaupack 20% 20% 20% 20% 20% 20%
- --------------------------------------------------------------------------------
Hydro Capacity Weighted Avg 40% 40% 40% 40% 40% 40%
- --------------------------------------------------------------------------------
Lower Mount Bethel N/A 41% 57% 63% 59% 53%
- --------------------------------------------------------------------------------
Lower Mount Bethel Duct N/A 8% 12% 18% 8% 8%
- --------------------------------------------------------------------------------
CC Capacity Weighted Average 0% 37% 51% 57% 52% 47%
- --------------------------------------------------------------------------------
Brunner Island Diesels 5% 8% 12% 13% 7% 6%
- --------------------------------------------------------------------------------
Martins Creek CT 0% 2% 2% 2% 1% 0%
- --------------------------------------------------------------------------------
Peaker Capacity Weighted Avg 1% 2% 3% 3% 2% 1%
- --------------------------------------------------------------------------------
Martins Creek Steam (gas)(1),(2) 0% 0% 0% 6% 0% 0%
- --------------------------------------------------------------------------------
Martins Creek Steam (oil)(1),(2) 0% 0% 0% 0% 0% 0%
- --------------------------------------------------------------------------------
Oil/Gas Steam Capacity 0% 0% 0% 3% 0% 0%
Weighted Avg
- --------------------------------------------------------------------------------
Eden 0% 14% 14% 18% 14% 12%
- --------------------------------------------------------------------------------
Upper Hanover 0% 8% 14% 14% 14% 12%
- --------------------------------------------------------------------------------
West Earl 0% 9% 14% 15% 14% 12%
- --------------------------------------------------------------------------------
LM6000 Capacity Weighted Avg 0% 10% 14% 15% 14% 12%
- --------------------------------------------------------------------------------
Note: Does not include taxes, debt, or some cost items such as new capital
additions. Includes revenue, short run variable costs and FERC Form 1 O&M.
1 These units are expected to operate during hotter than average summers
and/or during periods of greater than average outages. The associated
super peak revenues and/or capacity revenues are included in the analysis,
even though their dispatch levels were not adjusted for non-average
conditions.
2 NPV values incorporate revenues associated with NO(x) allowance
allocations. All allowances have been attributed to the gas unit as this
gas will likely be the fuel of choice in hours of operation.
As mentioned above, the PPL PJM assets are largely baseload units. These
units are projected to have relatively stable dispatch. Exhibits 7-23 and 7-24
show the placement of the PPL units in the PJM total regional supply curve. As
can be seen, the PPL units are well interspersed throughout the supply curve.
The majority of the PPL PJM units are in Western PJM. Likewise, most of the coal
units in PJM are concentrated in the West given its proximity to coal fields.
However, the rest of PJM has much more gas and oil fueled capacity. In this
broader regional context, the PPL baseload units face limited revenue risk as
most are relatively low cost units and dispatch before most natural gas and oil
units, even at low natural gas prices. Periods of low price spike or capacity
price revenue do not carry a high risk for these units since these units tend to
always dispatch among the first units in merit order. Given the competitive cost
position of the units, downside risk is limited for these units since they are
so low in the merit order of dispatch and so competitive in terms of variable
costs. Note, however, that periods of low gas prices could decrease long-term
average revenue.
- --------------------------------------------------------------------------------
191 [LOGO] ICF CONSULTING
Exhibit 7-23
Base Case Illustrative Summer Peak Supply Curve 2005 - PJM
[GRAPHIC]
Note: Zero cost generation includes hydro capacity, non-dispatchable
units, and portions of units operating on minimum turndown.
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
PPL also owns several smaller peaking units which are maintained at low
costs. These units add value to the portfolio by being able to supplement the
baseload and mid-level units in periods of price spikes or shortages. Note that
only those units analyzed are shown above.
The Base Case supply curve is representative of the dispatch order for the
Sensitivity Cases as well. The coal units are even better positioned in the High
Fuel Price Case since the gas-fired units will be dispatched at a higher rate.
- --------------------------------------------------------------------------------
192 [LOGO] ICF CONSULTING
Exhibit 7-24
Base Case Illustrative Summer Peak Supply Curve 2015 - PJM
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
NEPOOL Power Plants
The NEPOOL assets total 323 MW of capacity as compared to over 9 GW in
PJM. Although the assets total a much lower capacity, the mix between baseload,
mid-level, and peaking units is similar to that in PJM.
The former Bangor Hydro assets are very strong performers in all cases
with expected earnings of more than $1,600/kW (1998$) in the Base Case. The new
Wallingford unit performs well in the marketplace, capturing the mid-level and
peaking markets. The Wyman unit maintains its value over the entire forecast
horizon by being available to service the peak demand periods and hence capture
price spikes.
- --------------------------------------------------------------------------------
193 [LOGO] ICF CONSULTING
Exhibit 7-25
PPL NEPOOL Generating Stations Operating Revenue
- --------------------------------------------------------------------------------
NPV (1998$/kW)
Capacity ------------------------------
Site (MW) Base High Low
- --------------------------------------------------------------------------------
Wallingford 220 639 681 470
- --------------------------------------------------------------------------------
Wyman 4 (Oil/Gas Steam)(1) 52 615 671 433
- --------------------------------------------------------------------------------
NEPOOL Hydro Assets 42 2,036 2,294 1,688
- --------------------------------------------------------------------------------
Ellsworth Hydro 9 1,542 1,704 1,269
- --------------------------------------------------------------------------------
Hydro Total 51 1,949 2,190 1,614
- --------------------------------------------------------------------------------
Regional Portfolio Average 323 842 918 645
- --------------------------------------------------------------------------------
Note: Uses an 11.2 percent real discount rate.
1 PPL owns 52 MW of 615 MW of the Wyman 4 generating station.
Exhibit 7-26
PPL Station Forecast Base Case Capacity Factors - NEPOOL (%) - Base Case
- --------------------------------------------------------------------------------
2001 2003 2005 2010 2015 2020
- --------------------------------------------------------------------------------
Wallingford 6 18 24 18 16 11
- --------------------------------------------------------------------------------
Wyman 17 0 0 0 0 0
- --------------------------------------------------------------------------------
Hydro Assets 69 69 69 69 69 69
- --------------------------------------------------------------------------------
Ellsworth Hydro 38 38 38 38 38 38
- --------------------------------------------------------------------------------
Capacity Weighted
Average Hydro Capacity 64 64 64 64 64 64
Factor
- --------------------------------------------------------------------------------
The Wyman unit is a relatively expensive variable cost unit, especially
when compared to new gas turbines entering the market. Its dispatch is extremely
limited and it operates only in peak periods in our projections. Exhibit 7-27
shows the near- to mid-term operation of PPL units in NEPOOL. Note that the
Wyman unit dispatches only in super peak period and is not captured in this
graphic. Exhibit 7-28 shows the supply curve for 2010 representing Wyman's best
year of operation in our forecast horizon.
- --------------------------------------------------------------------------------
194 [LOGO] ICF CONSULTING
Exhibit 7-27
Base Case Illustrative Summer Peak Supply Curve 2001 - NEPOOL
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
Exhibit 7-28
Base Case Illustrative Summer Peak Supply Curve 2010 - NEPOOL
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with fixed
dispatch costs and units operating under turndown constraints.
- --------------------------------------------------------------------------------
195 [LOGO] ICF CONSULTING
WSCC Power Plants
The acquisition of the Montana Power Company assets gave PPL a dominant
presence in the Montana region. PPL has further expanded their asset base with
the addition of the Griffith generating station in Arizona, and the planned
capacity additions of Starbuck in the Pacific Northwest and Sundance in Arizona.
Coal and hydro units comprise the total Montana assets. The coal units are
very low cost and are located centrally to the PRB coal fields. These units
prove to be very valuable for meeting internal demand levels as well as
supplying low cost energy to neighboring regions.
Exhibit 7-29
PPL WSCC Generating Stations - Operating Revenues
- --------------------------------------------------------------------------------
NPV (1998$/kW)
-----------------------------
Plant Capacity Base High Low
- --------------------------------------------------------------------------------
Colstrip(1) (Montana) 530 1,532 1,718 1,138
- --------------------------------------------------------------------------------
J E Corette (Montana) 156 1,593 1,781 1,192
- --------------------------------------------------------------------------------
Montana Hydro (Montana) 556 1,801 1,947 1,459
- --------------------------------------------------------------------------------
Griffith (Arizona)(2) 210 880 824 663
- --------------------------------------------------------------------------------
Griffith Duct (Arizona) 60 628 580 475
- --------------------------------------------------------------------------------
Sundance (Arizona) 440 564 531 419
- --------------------------------------------------------------------------------
Starbuck (PacNW) 1,200 469 428 415
- --------------------------------------------------------------------------------
WSCC Regional Average 1,512 982 1,024 777
- --------------------------------------------------------------------------------
1 PPL owns 26 percent of the megawatts at the Colstrip plant. (50 percent of
units 1 & 2, 30 percent of unit 3, and no ownership rights at unit 4)
2 PPL owns 50 percent of the megawatts at the Griffith plant.
Exhibit 7-30
PPL WSCC Generating Stations - Projected Annual Capacity Factors (%)
- --------------------------------------------------------------------------------
Plant 2001 2003 2005 2010 2015 2020
- --------------------------------------------------------------------------------
Colstrip (Montana) 86 86 86 86 86 86
- --------------------------------------------------------------------------------
J E Corette (Montana) 88 88 88 88 88 88
- --------------------------------------------------------------------------------
Montana Hydro (Montana) 50 70 70 70 70 70
- --------------------------------------------------------------------------------
Griffith (Arizona) 84 88 79 86 92 92
- --------------------------------------------------------------------------------
Griffith Duct (Arizona) 51 23 13 16 25 30
- --------------------------------------------------------------------------------
Sundance (Arizona) N/A 19 4 5 6 3
- --------------------------------------------------------------------------------
Starbuck (PacNW) N/A N/A 78 70 66 18
- --------------------------------------------------------------------------------
Total Weighted Average 34 40 67 65 64 45
- --------------------------------------------------------------------------------
In Montana, the hydro and coal resources dispatch to full capability,
reflecting their high energy value. Exhibits 7-30 and 7-31 provide
representative supply curves for the Montana region.
- --------------------------------------------------------------------------------
196 [LOGO] ICF CONSULTING
Exhibit 7-31
Base Case Illustrative Summer Peak Supply Curve 2005 - Montana
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
Exhibit 7-32
Base Case Illustrative Summer Peak Supply Curve 2015 - Montana
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
- --------------------------------------------------------------------------------
197 [LOGO] ICF CONSULTING
As mentioned, the Montana units are very low cost, and hence well
positioned to serve demand in the WSCC. By 2015, additional peaking capacity is
required to maintain reliability as seem in the supply curve.
In Arizona/New Mexico, the PPL capacity is comprised of one combined cycle
unit, one duct firing block at the combined cycle units, and one LM6000 unit.
The Griffith power plant will be available in 2001 and performs well with
dispatch factors above 80 percent at the combined cycle portion of the plant. In
the long-term, performance of the facility improves to dispatch to full
availability. The duct burner at Griffith serves the peaking market and adds
value through being available in capacity price spike periods. The Griffith Duct
burner also tends to serve the mid-level market and as such as relatively high
dispatch, even outside of the peaking periods. Overall, the Griffith unit
performs well in the Arizona/New Mexico market.
The Sundance unit will not be available for dispatch in 2001, but performs
well in it's first year of operation. Thereafter, Sundance competes with more
efficient, and hence lower cost, gas-fired units. However, Sundance has an
advantage over other unit types because its non-fuel variable operating costs
are very low as are it's maintenance costs. It is also extremely flexible to
start and stop on extremely short notice without having major effects on the
total costs. As a result, it serves the peaking market and provides significant
value through being available in the price spike periods with a very low
maintenance cost.
Exhibit 7-33
Base Case Illustrative Summer Peak Supply Curve 2005 - Arizona/New Mexico
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with
fixed dispatch costs and units operating under turndown constraints.
- --------------------------------------------------------------------------------
198 [LOGO] ICF CONSULTING
Exhibit 7-34
Base Case Illustrative Summer Peak Supply Curve 2015 - Arizona/New Mexico
[GRAPH]
Note: Zero cost generation represents hydro units, NUG contracts with fixed
dispatch costs and units operating under turndown constraints.
The Griffith unit in Arizona is among a limited number of combined cycles
in the region. The unit performs well against other units in the region,
particularly existing oil/gas steam units. In the shoulder and winter months,
when gas prices are expected to be lower, Griffith may compete against higher
cost coal units as well.
- --------------------------------------------------------------------------------
199 [LOGO] ICF CONSULTING
Exhibit 7-35
Base Case Illustrative Summer Peak Supply Curve 2005 - Pacific Northwest
[GRAPH]
PPL is also expanding to include a 1,200 MW combined cycle facility in the
Pacific Northwest, the Starbuck unit. The Pacific Northwest is currently
dominated by baseload capacity, but is experiencing capacity tightness. As such,
new cpacity additions are very welcome in the region.
Exhibit 7-36
PPL LILCO Generating Stations Operating Revenue
- --------------------------------------------------------------------------------
NPV (1998$/kW)
Capacity -------------------------
Site (MW) Base High Low
- --------------------------------------------------------------------------------
Kings Park LM6000 270 476 469 387
- --------------------------------------------------------------------------------
Regional Portfolio Average 270 476 469 387
- --------------------------------------------------------------------------------
Note: Uses an 11.2 percent real discount rate.
1 PPL owns 52 MW of 615 MW of the Wyman 4 generating station.
Exhibit 7-37
PPL Station Forecast Base Case Capacity Factors - LILCO (%) - Base Case
- --------------------------------------------------------------------------------
2001 2003 2005 2010 2015 2020
- --------------------------------------------------------------------------------
Kings Park LM6000 N/A 33% 24% 15% 16% 12%
- --------------------------------------------------------------------------------
Capacity Weighted N/A 33% 24% 15% 16% 12%
Average
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
200 [LOGO] ICF CONSULTING
Exhibit 7-38
Base Case Illustrative Summer Peak Supply Curve 2005 - LILCO
[GRAPH]
The planned expansion units for the PPL portfolio also include LM6000
units in New York and in Illinois. The King's Park unit in Long Island will
compete against a number of higher costs units serving the local markets. As
such, it is very favorably positioned in the dispatch order and is expected to
maintain relatively high dispatch.
Exhibit 7-39
PPL ComEd Generating Stations Operating Revenue
- --------------------------------------------------------------------------------
NPV (1998$/kW)
Capacity -------------------------
Site (MW) Base High Low
- --------------------------------------------------------------------------------
University LM6000 540 487 516 380
- --------------------------------------------------------------------------------
Regional Portfolio Average 540 487 516 380
- --------------------------------------------------------------------------------
Note: Uses an 11.2 percent real discount rate.
1 PPL owns 52 MW of 615 MW of the Wyman 4 generating station.
Exhibit 7-40
PPL Station Forecast Base Case Capacity Factors - ComEd (%)
- --------------------------------------------------------------------------------
2001 2003 2005 2010 2015 2020
- --------------------------------------------------------------------------------
University LM6000 N/A 9% 10% 18% 28% 22%
- --------------------------------------------------------------------------------
Capacity Weighted N/A 9% 10% 18% 28% 22%
Average
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
201 [LOGO] ICF CONSULTING
Exhibit 7-41
Base Case Illustrative Summer Peak Supply Curve 2005 - ComEd
[GRAPH]
The ComEd region is in need of peaking capacity given it's historical
tendency toward large baseload units. The peaking units serving the market
currently are very high cost units. The University Facility will dispatch much
more favorably to these combustion turbine units although it's primary value is
in serving the peak periods in the market.
- --------------------------------------------------------------------------------
202 [LOGO] ICF CONSULTING
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
[Graphic]
$500,000,000
PPL ENERGY SUPPLY, LLC
OFFER TO EXCHANGE
SENIOR NOTES, 6.40% EXCHANGE SERIES A DUE 2011
(WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT)
FOR ANY AND ALL OUTSTANDING
SENIOR NOTES, 6.40% SERIES A DUE 2011
(WHICH HAVE NOT BEEN SO REGISTERED)
Until , 2002, 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 unsold
allotments or subscriptions.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PART II.
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Section 18-108 of the Delaware Limited Liability Company Act permits a
Delaware limited liability company to indemnify and hold harmless any member,
manager or other person from and against any and all claims and demands
whatsoever, subject only to the standards and restrictions, if any, as may be
set forth in the company's limited liability agreement. The Company's Limited
Liability Agreement contains provisions which limit liability to the fullest
extent permitted by applicable law.
Section 6.2 of the registrant's Limited Liability Agreement provides, in
part, as follows:
"To the fullest extent permitted by law, the Company shall indemnify and
hold harmless each Member, Manager or any officer director, stockholder,
partner, employee, representative, member, counsel or agent of any of the
foregoing, or any officer, employee, representative, counsel, director,
stockholder, partner or agent of the Company or any of its affiliates (each a
"Covered Person") from and against any and all losses, claims, demands,
liabilities, expenses, judgments, fines, settlements and other amounts arising
from any and all claims, demands, actions, suits or proceedings, civil,
criminal, administrative or investigative ("Claims"), in which the Covered
Person may be involved, or threatened to be involved, as a party or otherwise,
by reason of its management of the affairs of the Company or which relates to
or arises out of the Company or its property, business or affairs. A Covered
Person shall not be entitled to indemnification under this Section 6.2 with
respect to (i) any Claim with respect to which such Covered Person has engaged
in fraud, willful misconduct, bad faith or gross negligence or (ii) any Claim
initiated by such Covered Person unless such Claim (or part thereof) (A) was
brought to enforce such Covered Person's rights to indemnification hereunder or
(B) was authorized or consented to by the Board. Expenses incurred by a Covered
Person in defending any Claim shall be paid by the Company in advance of the
final disposition of such Claim upon receipt by the Company of an undertaking
by or on behalf of such Covered Person to repay such amount if it shall be
ultimately determined that such Covered Person is not entitled to be
indemnified by the Company as authorized by this Section 6.2."
"Any repeal or modification of this Article VI by the Member shall not
adversely affect any rights of such Covered Person pursuant to this Article VI,
including the right to indemnification and to the advancement of expenses of a
Covered Person existing at the time of such repeal or modification with respect
to any acts or omissions occurring prior to such repeal or modification."
The Company presently has insurance policies which, among other things,
include liability insurance coverage for officers and directors of the Company,
under which such officers and directors are covered against any "loss" by
reason of payment of damages, judgments, settlements and costs, as well as
charges and expenses incurred in the defense of actions, suits or proceedings.
"Loss" is specifically defined to exclude fines and penalties, as well as
matters deemed uninsurable under the law pursuant to which the insurance policy
shall be construed. The policies also contain other specific exclusions,
including illegally obtained personal profit or advantage, and dishonesty.
ITEM 21. EXHIBITS.
Reference is made to the Exhibit Index on p. II-4 hereof.
ITEM 22. UNDERTAKINGS.
The undersigned registrant hereby undertakes:
(1) To respond to requests for information that is incorporated by
reference into the prospectus pursuant to item 4, 10(b), 11 or 13 of Form
S-4, 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 this registration statement through the date of responding
to the request;
II-1
(2) 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 an included in the registration statement when
it became effective.
Insofar as indemnification for liabilities arising under the Securities Act
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 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 against the
registrant by such director, officer or controlling person in connection with
the securities being registered, such 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 whether such indemnification by
it is against public policy as expressed in the Securities Act and will be
governed by the final adjudication of such issue.
II-2
POWER OF ATTORNEY
Each member of the board of managers and/or officer of the registrant whose
signature appears below hereby appoints John R. Biggar, James E. Abel and
Robert J. Grey, and each of them severally, as his true and lawful
attorney-in-fact and agent to sign in his name and behalf, in any and all
capacities stated below, and to file with the Securities and Exchange
Commission, any and all amendments, including post effective amendments, to
this registration statement, and the registrant hereby also appoints each such
person as its attorney-in-fact and agent with like authority to sign and file
any such amendments in its name and behalf.
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Allentown, and
Commonwealth of Pennsylvania on the 7th day of December, 2001.
PPL ENERGY SUPPLY, LLC
/S/ WILLIAM F. HECHT
--------------------------------------
WILLIAM F. HECHT, PRESIDENT AND
MEMBER OF THE BOARD OF MANAGERS
Pursuant to the requirements of the Securities Act of 1933, as amended, this
registration statement has been signed by the following persons in the
capacities and on the 7th day of December, 2001.
SIGNATURE TITLE
--------- -----
/s/ WILLIAM F. HECHT Principal Executive Officer and
------------------------------ Member of the Board of Managers
WILLIAM F. HECHT, PRESIDENT
/s/ JAMES E. ABEL Principal Financial Officer and Member
------------------------------ of the Board of Managers
JAMES E. ABEL, TREASURER
/s/ JOSEPH J. MCCABE Controller and Member of the Board of
------------------------------ Managers
JOSEPH J. MCCABE, CONTROLLER
/s/ JOHN R. BIGGAR Member of the Board of Managers
------------------------------
JOHN R. BIGGAR, VICE PRESIDENT
/s/ LAWRENCE E. DE SIMONE Member of the Board of Managers
------------------------------
LAWRENCE E. DE SIMONE
/s/ ROBERT J. GREY Member of the Board of Managers
------------------------------
ROBERT J. GREY
II-3
PPL ENERGY SUPPLY, LLC REGISTRATION STATEMENT ON FORM S-4
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION OF EXHIBIT METHOD OF FILING
- ----------- ---------------------- ----------------
3.1 Certificate of Formation of PPL Energy Supply Filed herewith
3.2 Limited Liability Company Agreement of PPL Energy Supply, dated Filed herewith
March 20, 2001
4.1 Indenture dated as of October 1, 2001, by PPL Energy Supply and Filed herewith
The Chase Manhattan Bank, as Trustee
4.2 Supplemental Indenture No. 1 to Indenture Filed herewith
4.3 Form of Officer's Certificate establishing the form and terms of the New Filed herewith
Notes
4.4 Form of New Note Filed herewith
4.5 Registration Rights Agreement between PPL Energy Supply and the Initial Filed herewith
Purchasers
5.1 Opinion of Michael A. McGrail, Esq. Filed herewith
5.2 Opinion of Thelen Reid & Priest LLP Filed herewith
8 Opinion as to tax matters of Thelen Reid & Priest LLP Filed herewith
as part of Exhibit 5.2
10.1 $600 Million 364-Day Credit Agreement, dated as of June 26, 2001, among Exhibit 10(a) to PPL
PPL Energy Supply, PPL Corporation and the banks named therein Corporation Quarterly
Report on Form 10-Q
for the quarter ended
June 30, 2001
10.2 $500 Million Three-Year Credit Agreement, dated as of June 26, 2001, Exhibit 10(b) to PPL
among PPL Energy Supply, PPL Corporation and the banks named therein Corporation Quarterly
Report on Form 10-Q
for the quarter ended
June 30, 2001
10.3 364-Day Revolving Credit Agreement, dated as of June 26, 2001, among Filed herewith
PPL Energy Supply, PPL Corporation and PPL Capital Funding
10.4 $150 Million Credit and Reimbursement Agreement, dated as of April 25, Exhibit 10(d) to PPL
2001, among PPL Montana and the banks named therein Corporation Quarterly
Report on Form 10-Q
for the quarter ended
June 30, 2001
10.5 Generation Supply Agreement, dated as of June 20, 2001, between PPL Filed herewith
Electric Utilities and PPL EnergyPlus
10.6 Amended and Restated PPL Supply Guarantee, dated as of July 17, 2001, in Filed herewith
favor of Large Scale Distributed Generation II Statutory Trust
10.7 Amended and Restated Directors Deferred Compensation Plan, effective Exhibit 10(h) to PPL
February 14, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
II-4
EXHIBIT NO. DESCRIPTION OF EXHIBIT METHOD OF FILING
- ----------- ---------------------- ----------------
10.8 Amended and Restated Officers Deferred Compensation Plan, effective Exhibit 10(i)-1 to PPL
February 14, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.9 Amendment No. 1 to said Officers Deferred Compensation Plan, effective Exhibit 10(i)-2 to PPL
July 1, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.10 Amendment No. 2 to said Officers Deferred Compensation Plan, effective Exhibit 10(i)-3 to PPL
July 1, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.11 Amended and Restated Supplemental Executive Retirement Plan, effective Exhibit 10(j)-1 to PPL
October 1, 1999 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.12 Amendment No. 1 to said Supplemental Executive Retirement Plan, Exhibit 10(j)-2 to PPL
effective July 1, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.13 Amended and Restated Incentive Compensation Plan, effective Exhibit 10(k) to PPL
February 14, 2000 Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.14 Short-Term Incentive Plan Schedule B to Proxy
Statement of PPL
Corporation, dated
March 12, 1999
10.15 Form of Severance Agreement entered into between PPL Corporation and Exhibit 10 to PPL
Officers Corporation Quarterly
Report on Form 10-Q
for the quarter ended
June 30, 1998
10.16 Agreement, effective May 24, 2000, between PPL Corporation and Paul T. Exhibit 10(n) to PPL
Champagne Corporation Annual
Report on Form 10-K
for the year ended
December 31, 2000
10.17 Equity Contribution Agreement among PPL Corporation, PPL Montana and Exhibit 10.15 to PPL
The Chase Manhattan Bank, as Trustee Montana Form S-4
Registration Statement
(File No. 333-50350)
II-5
EXHIBIT NO. DESCRIPTION OF EXHIBIT METHOD OF FILING
- ----------- ---------------------- ----------------
10.18 Facility Lease Agreement (BA 1/2) between PPL Montana and Montana Exhibit 4.7a to PPL
OL3 LLC Montana S-4
Registration
Statement (File No.
333-50350)
10.19 Facility Lease Agreement (BA 3) between PPL Montana and Montana Exhibit 4.8a to PPL
OL4 LLC Montana S-4
Registration
Statement (File No.
333-50350)
10.20 Services Agreement, dated as of July 1, 2000, among PPL Corporation, Filed herewith
PPL Energy Funding and its direct and indirect subsidiaries in various tiers,
PPL Capital Funding, Inc., PPL Gas Utilities Corporation, PPL Services
and CEP Commerce, LLC
12 Statement of Computation of Ratio of Earnings to Fixed Charges Filed herewith
21 Subsidiaries of PPL Energy Supply Filed herewith
23.1 Consent of Michael A. McGrail, Esq. Filed herewith as part
of Exhibit 5.1
23.2 Consent of Thelen Reid & Priest LLP Filed herewith as part
of Exhibit 5.2
23.3 Consent of PricewaterhouseCoopers LLP Filed herewith
23.4 Consent of PricewaterhouseCoopers Filed herewith
23.5 Consent of Arthur Andersen Filed herewith
23.6 Consent of Stone & Webster Consultants, Inc. Filed herewith
23.7 Consent of ICF Resources, Inc. Filed herewith
24 Power of Attorney (contained on page II-3).
25 Statement of Eligibility of Trustee on Form T-1 of JPMorgan Chase Bank Filed herewith
(formerly known as The Chase Manhattan Bank)
99.1 Form of Letter of Transmittal Filed herewith
99.2 Form of Notice of Guaranteed Delivery Filed herewith
II-6