AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 8, 2002
REGISTRATION NO. 333-72498
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
AMENDMENT NO. 1 TO
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
---------------------
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
(Exact name of registrant as specified in its charter)
DELAWARE 4911 23-3020481
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification
incorporation or organization) Classification Code Number) No.)
10435 DOWNSVILLE PIKE
HAGERSTOWN, MARYLAND 21740-1766
(301) 790-3400
(Address, including zip code, and telephone number, including area
code, of registrant's principal executive offices)
---------------------
THOMAS K. HENDERSON
VICE PRESIDENT
10435 DOWNSVILLE PIKE
HAGERSTOWN, MARYLAND 21740-1766
(301) 790-3400
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
---------------------
COPY TO:
ROBERT E. BUCKHOLZ, JR.
SULLIVAN & CROMWELL
125 BROAD STREET
NEW YORK, NEW YORK 10004-2498
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE
PUBLIC: As soon as practicable after the effective date of this registration
statement.
If the securities being registered on this Form are being offered in connection
with the formation of a holding company and there is compliance with General
Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering pursuant
to Rule 462(b) under the Securities Act, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
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CALCULATION OF REGISTRATION FEE
===================================================================================================================================
TITLE OF EACH CLASS OF PROPOSED MAXIMUM AMOUNT OF
SECURITIES PROPOSED MAXIMUM AGGREGATE OFFERING REGISTRATION FEE
TO BE REGISTERED AMOUNT TO BE REGISTERED OFFERING PRICE PER UNIT PRICE (1) (2)
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7.80% Notes due 2011 $400,000,000 100% $400,000,000 $100,000
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(1) Estimated in accordance with Rule 457(f) under the Securities Act of 1933
as amended, solely for purposes of calculating the registration fee.
(2) Previously paid.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE 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 we are not soliciting offers to buy these
securities in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED JANUARY 8, 2002
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
OFFER TO EXCHANGE UP TO
$400,000,000
7.80% NOTES DUE 2011
WHICH HAVE BEEN REGISTERED UNDER THE
SECURITIES ACT OF 1933
FOR
ALL OUTSTANDING UNREGISTERED
7.80% NOTES DUE 2011
We are offering to exchange new 7.80% Notes due 2011, that we have registered
under the Securities Act of 1933, for all of our outstanding 7.80% Notes due
2011, which were previously issued pursuant to an exemption from registration
under the Securities Act of 1933. We refer to these registered notes as the new
notes and the outstanding unregistered notes as the old notes.
THE EXCHANGE OFFER
o We will exchange an equal principal amount of new notes that are freely
tradeable for all old notes that are validly tendered and not validly
withdrawn
o You may withdraw tenders of outstanding old notes at any time prior to the
expiration of the exchange offer
o The exchange offer is subject to the satisfaction of limited, customary
conditions
o The exchange offer expires at 5:00 p.m., New York time, on February , 2002,
unless extended
o The exchange of old notes for new notes in the exchange offer generally
will not be a taxable event for U.S. federal income tax purposes
o We will not receive any proceeds from the exchange offer
THE NEW NOTES
o We are offering the new notes in order to satisfy our obligations under the
registration rights agreement entered into in connection with the private
placement of the old notes
o The terms of the new notes to be issued in the exchange offer are
substantially identical to the terms of the old notes, except that the new
notes are registered under the Securities Act and have no transfer
restrictions, rights to additional interest or registration rights except
in limited circumstances
---------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 12 TO READ ABOUT FACTORS YOU SHOULD
CONSIDER IN CONNECTION WITH THE EXCHANGE OFFER.
If you are a broker-dealer that receives new notes for your own account as a
result of market-making or other trading activities, you must acknowledge that
you will deliver a prospectus in connection with any resale of the new notes.
The letter of transmittal accompanying this prospectus states that by so
acknowledging and by delivering a prospectus, you will not be deemed to admit
that you are an "underwriter" within the meaning of the Securities Act. You may
use this prospectus, as we may amend or supplement it in the future, for your
resales of new notes. We will make this prospectus available to any
broker-dealer for use in connection with any such resale for a period of 180
days after the date of expiration of this exchange offer.
---------------------------
Neither the Securities and Exchange Commission nor any other regulatory body has
approved or disapproved of the new notes or passed upon the accuracy or adequacy
of this prospectus. Any representation to the contrary is a criminal offense.
---------------------------
The date of this prospectus is January , 2002
TABLE OF CONTENTS
PAGE
SUMMARY...................................................................3
RISK FACTORS ...........................................................12
FORWARD-LOOKING STATEMENTS ..............................................22
USE OF PROCEEDS .........................................................22
RATIO OF EARNINGS TO FIXED CHARGES ......................................23
CAPITALIZATION AND SHORT-TERM DEBT ......................................23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS .........................................24
ALLEGHENY ENERGY SUPPLY COMPANY, LLC ...................................48
MANAGEMENT...............................................................77
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...........79
CERTAIN TRANSACTIONS ....................................................80
THE EXCHANGE OFFER ......................................................83
DESCRIPTION OF NOTES ....................................................92
IMPORTANT FEDERAL INCOME TAX CONSIDERATIONS .............................99
EXPERTS .................................................................99
PLAN OF DISTRIBUTION ...................................................100
VALIDITY OF THE NOTES ..................................................100
AVAILABLE INFORMATION...................................................100
INDEX TO FINANCIAL STATEMENTS ..........................................F-1
OPERATING DATA FOR MIDWEST ASSETS ACQUIRED FROM
ENRON NORTH AMERICA CORPORATION....................................O-1
-2-
SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE
READ TOGETHER WITH, THE MORE DETAILED FINANCIAL AND OTHER INFORMATION INCLUDED
IN THIS PROSPECTUS, INCLUDING THE INFORMATION CONTAINED IN THE SECTION ENTITLED
"RISK FACTORS," BEGINNING ON PAGE 12.
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
We are a rapidly growing merchant energy company with 14,687 megawatts,
or MW, of generating capacity owned, controlled, under construction or in
development, pending transfer from affiliates or planned as facility expansions.
We currently own 8,796 MW in the Eastern and Midwestern regions of the United
States and have the contractual right to control 1,000 MW in California. We are
expanding our generation fleet by 2,731 MW through the announced construction
and development of new facilities, acquisition of contractual rights to control
generating capacity and planned expansions to existing facilities. It is our
goal to complete the transfer of an additional 2,160 MW in the Eastern markets
from our parent, Allegheny Energy, Inc. and its subsidiaries. We manage all of
our generation assets as an integrated portfolio with our energy trading, fuel
procurement, power marketing and risk management activities. We have begun to
significantly expand our generation development efforts and our acquisition
activity nationally in markets that have capacity shortages and attractive
competitive characteristics.
The national reach of our Energy Trading Business, which we acquired
from Merrill Lynch in March 2001, will help us to expand from a regional to a
national merchant energy company. This business provides us with valuable market
intelligence to aid our acquisition and development activities and allows us to
provide customized energy solutions to wholesale, industrial and commercial
customers.
A key step in the development of our business was the negotiated
transfers to us of 6,230 MW of generating assets by the regulated utility
subsidiaries of our parent, Allegheny Energy. These transfers were made at net
book value as part of the deregulation settlements in their respective States.
These generating assets consist primarily of low-cost, coal-fired, base-load
facilities strategically located in the expanded wholesale and retail
electricity market made possible by the creation of PJM-West. PJM-West is a new
contractual arrangement that we expect will be operational in the first quarter
of 2002 and which we expect will integrate, for the first time, our traditional
regional markets in the East Central Area Reliability Region and the liquid
regional trading markets of the Pennsylvania-New Jersey-Maryland market,
commonly known as the PJM market. Altogether, we now have access to six of the
most liquid trading hubs east of the Mississippi River.
In connection with the transfers of assets from the regulated utility
subsidiaries, we have long-term power sales agreements with these companies to
fulfill their provider-of-last-resort obligations to customers. As the amounts
of electricity we must deliver under the power sales agreements decrease over
time, the prices escalate. A significant portion of the normal operating
capacity of our fleet of transferred generating assets is currently required to
fulfill our obligations under these power sales agreements. The transition to
market prices will be phased in for these companies at different times between
2003 and 2008, depending upon the state and the customer class. The contracted
prices provide us with a stable source of revenue during the transition period.
We were formed in November 1999 as a wholly-owned subsidiary of
Allegheny Energy to take advantage of the opportunities in the electric power
market as a result of economic factors and federal and state legislative and
regulatory changes related to the development of competitive markets. Today,
Allegheny Energy continues to have an approximately 98% ownership interest in
us. You may contact us at 10435 Downsville Pike, Hagerstown, Maryland,
21740-1766, Attention: Investor Relations, Telephone: 301-665-2713.
-3-
RECENT DEVELOPMENTS
CORPORATE RESTRUCTURING
In November 2001, we and our parent, Allegheny Energy, filed an
application with the SEC seeking authorization under the Public Utility Holding
Company Act of 1935 to restructure our corporate organization by creating a new
Maryland holding company into which we will then merge. We will thereby be
changed from a Delaware limited liability company into a Maryland corporation.
We and our parent, Allegheny Energy, also sought authorization to merge
Allegheny Energy Global Markets, one of our wholly-owned subsidiaries, into this
Maryland holding company, which will then continue to conduct the energy
commodity marketing and trading activities of Allegheny Energy Global Markets.
On December 31, 2001, we received SEC approval to effect this reorganization.
INITIAL PUBLIC OFFERING AND DISTRIBUTION
On July 23, 2001 Allegheny Energy filed an application with the SEC
seeking authorization under the Public Utility Holding Company Act of 1935 to:
o effect an initial public offering of up to 18% of the common stock of the
new Maryland holding company, which we intend to complete when favorable
market and other conditions exist; and
o distribute the remaining common stock of the new Maryland holding company
owned by Allegheny Energy and not sold in the initial public offering to
the stockholders of Allegheny Energy on a tax-free basis within 24 months
following the completion of the initial public offering.
MIDWEST ASSETS ACQUISITION
In May 2001, we acquired three natural gas-fired generating facilities
totaling 1,710 MW of peaking capacity from Enron North America Corp. These
generating facilities include the 656 MW Lincoln Energy Center plant in
Illinois, the 508 MW Wheatland plant in Indiana and the 546 MW Gleason plant in
Tennessee. We refer to these assets as our Midwest Assets. The value of these
assets is enhanced by their location, which allows us to charge fees for
ancillary services to the transmission systems in these regions, in addition to
providing energy in periods of peak demand.
ENERGY TRADING BUSINESS
In March 2001, we acquired the energy commodity marketing and trading
business of Merrill Lynch Capital Services, Inc., which we refer to as the
Energy Trading Business and which now operates as Allegheny Energy Global
Markets, LLC, one of our wholly-owned subsidiaries. This Energy Trading Business
helps us optimize our portfolio of generating assets by significantly enhancing
our wholesale marketing, energy trading, fuel procurement and risk management
activities. The Energy Trading Business has also expanded our expertise in
nation-wide trading, fuel procurement, market analysis and risk management. We
are therefore better able to identify opportunities to expand our acquisition
and development activities and to compete outside our traditional regions. In
addition, the Energy Trading Business enables us to provide customized energy
management solutions to wholesale, industrial and commercial customers.
RECENT POWER SALES AGREEMENTS
In March 2001, we entered into a power sales agreement with the
California Department of Water Resources. Under this agreement, we have
committed to supply the State of California with electricity through December
2011. Deliveries of power have begun, with contract volumes varying from 150 MW
to 500 MW through December 2004. For the last seven years of the agreement, the
contract volume will be fixed at 1,000 MW. We plan to supply this power
primarily through our contractual control of 1,000 MW of generating capacity in
California, which we acquired as part of the acquisition of the Energy Trading
Business.
-4-
In August 2001, we were a successful bidder to supply Baltimore Gas &
Electric Company with electricity from July 2003 through June 2006. We are
committed to supply Baltimore Gas & Electric Company with an amount needed to
fulfill 10% of its provider-of-last-resort obligations.
STRATEGY
Our strategy is to continue to transform our company from a regional
merchant market operator of formerly regulated utility generation assets to a
competitive national energy merchant with energy marketing and customized energy
management solutions capabilities for our customers.
We plan to implement our growth plan with the following strategies:
o continue to transform from a regional to a national presence in the
United States by:
-- developing new greenfield power stations in attractive markets
and expanding our existing stations;
-- entering into additional contractual arrangements to control and
operate generation and natural gas assets owned by others; and
-- acquiring generation and natural gas assets in targeted markets.
o expand and diversify our base-load, coal-fired generation fleet to
include a combined coal and natural gas-fired portfolio of assets with
dispatch and geographic diversity.
o transfer additional generating assets from our affiliates.
o manage our power generation, energy trading, fuel procurement, power
marketing and risk management activities to:
-- optimize our portfolio of generation assets;
-- control our fuel and electricity commodity risk;
-- enhance development and acquisition opportunities; and
-- design customized energy management solutions for our customers.
o maintain an investment grade credit rating.
COMPETITIVE ADVANTAGES
We believe that we are well positioned to become one of the premier
national energy merchants because of our large and cost-efficient generation
fleet, our extensive market knowledge and risk management expertise and strong
credit position. Our significant competitive advantages include:
o STRATEGIC LOCATION AND COST EFFICIENT TRANSFERRED GENERATING ASSETS.
We currently own 8,796 MW of capacity of which 6,230 MW have been
transferred to us by Allegheny Energy's regulated utility
subsidiaries. The competitive advantages of these transferred
generating assets are as follows:
-- they were transferred to us at a net book value at the time of
transfer of approximately $257 per kilowatt, or kW;
-5-
-- they are primarily coal-fired, have a low fuel cost and low
variable operating and maintenance cost totaling approximately
$17 per MWh, and have attractive transportation costs due to
their proximity to our primary fuel source in the Appalachian
coal-mining region;
-- most of these assets are in the East Central Area Reliability
Region, strategically located in the expanded wholesale and
retail electricity market made possible by the creation of
PJM-West; and
-- most of the personnel that operated these generating assets for
the regulated utility subsidiaries of Allegheny Energy continue
to operate these assets for us.
o PREMIER ENERGY TRADING, FUEL PROCUREMENT, POWER MARKETING AND RISK
MANAGEMENT SKILLS. Our energy trading, fuel procurement, power
marketing and risk management skills allow us to optimize our
portfolio of generating assets by:
-- taking advantage of and profiting from regional supply and demand
patterns, capacity shortages, transmission constraints and
weather throughout the United States;
-- helping us identify attractive opportunities for expanding
generating capacity through acquisitions, development or
contractual arrangements; and
-- giving us the ability to opportunistically trade and source fuel
for our generating assets from various locations.
o DEMONSTRATED ABILITY TO EXPAND INTO COMPETITIVE MARKETS. Since our
formation in November 1999, we have demonstrated our ability to
transform our company from a regional generation company to a
competitive national energy merchant by:
-- implementing approved deregulation settlements in the various
states applicable to our business. These settlements allowed the
transfer to us of generating assets in 1999, 2000 and 2001 from
the regulated utility subsidiaries of Allegheny Energy;
-- acquiring the Energy Trading Business from Merrill Lynch in March
2001;
-- acquiring three natural gas-fired generating facilities totaling
1,710 MW of capacity in the Midwest from Enron in May 2001;
-- announcing the construction and development of 2,382 MW of
capacity located in the Eastern, Midwestern and Southwestern
markets of the United States; and
-- signing long-term contractual control arrangements of
approximately 1,300 MW of generation capacity in the Eastern and
Southwestern markets of the United States.
o STRONG CREDIT POSITION. We currently have senior unsecured debt credit
ratings of Baa1 from Moody's and BBB+ from Standard & Poor's and
Fitch. We believe our strong credit position and credit ratings:
-- provide us with financial flexibility that will be important as
we grow our business;
-- give Allegheny Energy Global Markets a stronger credit position
compared to less highly rated industry participants when it
enters into transactions with counterparties; and
-- reduce borrowing costs and credit amounts needed to cover risk
exposures compared to less highly rated industry participants.
-6-
THE EXCHANGE OFFER
Background On March 15, 2001, we completed a private placement of our
outstanding, unregistered notes. We refer to these as the
"old notes." In connection with that private placement, we
entered into a registration rights agreement in which we
agreed to deliver this prospectus to you and to make an
exchange offer.
The Exchange Offer We are offering to exchange up to $400 million principal
amount of our new notes which have been registered under the
Securities Act for up to $400 million principal amount of
our old notes. We refer to the registered notes as "new
notes." You may tender old notes only in integral multiples
of $1,000 principal amount. You should read the discussion
under the heading "THE EXCHANGE OFFER" beginning on page 83
for further information about the exchange offer and resale
of the new notes.
Resale of New Based on interpretive letters of the SEC staff to third
Notes parties, we believe that you may resell and transfer the new
notes issued pursuant to the exchange offer in exchange for
old notes without compliance with the registration and
prospectus delivery provisions of the Securities Act, if:
o you are acquiring the new notes in the ordinary course
of your business;
o you have no arrangement or understanding with any
person to participate in the distribution of the new
notes; and
o you are not our affiliate as defined under Rule 405 of
the Securities Act.
If you fail to satisfy any of these conditions, you must
comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a
resale of the new notes.
Broker-dealers that acquired old notes directly from us, but
not as a result of market-making activities or other trading
activities, must comply with the registration and prospectus
delivery requirements of the Securities Act in connection
with a resale of the new notes.
Each broker-dealer that receives new notes for its own
account pursuant to the exchange offer in exchange for old
notes that it acquired as a result of market-making or other
trading activities must deliver a prospectus in connection
with any resale of the new notes and provide us with a
signed acknowledgement of this obligation.
Consequences If Old notes that are not tendered in the exchange offer
You Do Not or are not accepted for exchange will continue to
Exchange Your bear legends restricting their transfer. You will not be
Old Notes able to offer or sell the old notes unless:
o an exemption from the requirements of the Securities
Act is available to you; or
o you sell the old notes outside the United States in
accordance with the SEC's Regulation S.
-7-
Remaining old notes will continue to be subject to
restrictions on transfer. See "THE EXCHANGE
OFFER--CONSEQUENCES OF FAILURES TO PROPERLY TENDER OLD NOTES
IN THE EXCHANGE," beginning on page 90.
Expiration Date 5.00 p.m., New York time, on February , 2002, unless we
extend the exchange offer.
Conditions to the The exchange offer is subject to limited, customary
Exchange Offer conditions, which we may waive.
Procedures for If you wish to accept the exchange offer, the following must
Tendering Old Notes be delivered to the exchange agent:
o for old notes tendered electronically, an agent's
message from The Depository Trust Company, which we
refer to as DTC, stating that the tendering participant
agrees to be bound by the letter of transmittal and the
terms of the exchange offer;
o your old notes by timely confirmation of book entry
transfer through DTC; and
o all other documents required by the letter of
transmittal.
These actions must be completed before the expiration of the
exchange offer.
If you hold old notes through DTC, you must comply with
their standard procedures for electronic tenders, by which
you will agree to be bound by the letter of transmittal.
By signing, or by agreeing to be bound by the letter of
transmittal, you will be representing to us that:
o you will be acquiring the new notes in the ordinary
course of your business;
o you have no arrangement or understanding with any
person to participate in the distribution of the new
notes;
o you are not our affiliate as defined under Rule 405 of
the Securities Act;
o you have full power and authority to tender, exchange
and transfer the old notes; and
o we will acquire good title to the old notes free and
clear of any liens, encumbrances, adverse claims or
other restrictions.
Guaranteed If you cannot meet the expiration deadline, deliver any
Delivery Procedures necessary documentation or comply with the applicable
for Tendering Old procedures under DTC standard operating procedures for
Notes electronic tenders in a timely fashion, you may tender your
old notes according to the guaranteed delivery procedures
set forth under "THE EXCHANGE OFFER--GUARANTEED DELIVERY
PROCEDURES."
Withdrawal Rights You may withdraw your tender of old notes any time before
the exchange offer expires.
-8-
Tax Consequences The exchange pursuant to the exchange offer generally will
not be a taxable event for U. S. federal income tax
purposes. See "IMPORTANT FEDERAL INCOME TAX CONSIDERATIONS."
Use of Proceeds We will not receive any proceeds from the exchange or the
issuance of new notes in connection with the exchange offer.
Exchange Agent Bank One Trust Company is serving as exchange agent in
connection with the exchange offer. The address and
telephone number of the exchange agent are set forth under
"THE EXCHANGE OFFER--EXCHANGE AGENT."
-9-
SUMMARY DESCRIPTION OF THE NEW NOTES
The form and terms of the new notes are the same as the form and terms
of the old notes, except that:
o the new notes will be registered under the Securities Act and will
therefore not bear legends restricting their transfer; and
o the provisions for payment of additional interest in case of
non-registration will be eliminated.
The new notes will evidence the same debt as the old notes and will rank
equally with the old notes. The same indenture will govern both the old notes
and the new notes.
You should read the discussion under the heading "DESCRIPTION OF NOTES"
beginning on page 92 for further information about the new notes.
TERMS OF THE NEW NOTES
The specific financial terms of the new notes are as follows:
o Title: 7.80% Notes due 2011
o Issuer: Allegheny Energy Supply Company, LLC
o Total principal amount being issued: $400,000,000
o Due date for principal: March 15, 2011
o Interest rate: 7.80% annually
o Special interest: On December 10, 2001, special interest will start
accruing at a rate of 0.25% per annum during the 90-day period
immediately following that date and shall increase by 0.25% per annum
at the end of each subsequent 90-day period that this registration
statement is not effective, but in no event shall the rate exceed
0.50% per annum.
o Due dates for interest: every March 15 and September 15
o Regular record dates for interest: every March 1 and September 1
o Ratings: "Baa1" by Moody's, "BBB+" by Standard & Poor's and "BBB+" by
Fitch. A rating is not a recommendation to buy, sell or hold new notes
and may be suspended, reduced or withdrawn at any time by Moody's,
Standard & Poor's and Fitch if our financial condition or results of
operations change. Each rating should also be evaluated independently
of any other rating
o Optional Redemption: at any time at our option at a redemption price
equal to 100% of the principal amount of the new notes to be redeemed
plus accrued interest, if any, plus a premium, calculated using a
discount rate equal to the interest rate on comparable U.S. treasury
securities plus 35 basis points
o Repayment at option of Holder: none
o The covenants, events of default and other provisions of the new notes
are identical to those contained in the old notes
-10-
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
SELECTED FINANCIAL INFORMATION
The following selected historical financial information as of and for
the year ended December 31, 2000 and as of December 31, 1999 and for the period
November 18, 1999 to December 31, 1999 has been derived from the audited
consolidated financial statements of the Company which are included elsewhere in
this prospectus. The statement of operations data for the nine months ended
September 30, 2001 and the balance sheet data as of September 30, 2001 have been
derived from our unaudited consolidated financial statements, which, in our
opinion, reflect all adjustments (consisting only of normal recurring
adjustments) necessary for a fair presentation. The selected financial
information should be read in conjunction with "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the consolidated
financial statements and accompanying notes included elsewhere in this
prospectus.
From
November 18, 1999
Nine Months Ended Year Ended Inception Date to
September 30, December 31, December 31,
2001 2000 1999
------------------ ------------- ----------------
(THOUSANDS OF DOLLARS)
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Operating revenues:
Retail................................................ $ 113,238 $ 197,189 $ 21,283
Wholesale............................................. 6,114,380(1) 1,285,102 73,259
Affiliated............................................ 845,362 777,281 46,332
------------- ----------- ------------
Total operating revenues........................... 7,072,980 2,259,572 140,874
Cost of sales and other operating expenses 6,639,969(1) 2,115,579 127,904
------------- ----------- ------------
Operating income...................................... 433,011 143,993 12,970
Other income and expenses................................ 4,938(1) 3,542 1,159
Interest charges, net.................................... 74,048(1) 33,458 2,093
------------- ----------- ------------
Consolidated income before income taxes, minority
interest, and cumulative effect of accounting change.. 363,901 114,077 12,036
Federal and state income taxes........................... 129,044(1) 36,081 2,504
Minority interest........................................ 3,646 2,508
------------- ----------- ------------
Consolidated income before cumulative effect of accounting
change................................................ 231,211 75,488 9,532
------------- ----------- ------------
Cumulative effect of accounting change................... (31,147)(2)
------------- ----------- ------------
Consolidated net income............................... $ 200,064 $ 75,488 $ 9,532
------------- ----------- ------------
September 30, December 31, December 31,
2001 2000 1999
------------- ---------------------- ------------
(THOUSANDS OF DOLLARS)
CONSOLIDATED BALANCE SHEET DATA:
Total assets............................................. $ 6,024,667(1)(3) $ 2,607,572 $ 1,375,506
Short-term debt and notes payable to parent and affiliates $ 1,366,052(1)(3) $ 219,015 $ 21,200
Long-term debt due within one year....................... 83,507
Long-term debt........................................... 892,714(1) 563,433 356,239
Minority interest........................................ 30,912 38,980
Members' equity.......................................... 1,520,448 759,643 512,699
------------ ----------- ------------
Total capitalization and short-term debt.............. $ 3,893,633 $ 1,581,071 $ 890,138
------------ ----------- ------------
- --------------------
(1) Reflects the acquisition of the Energy Trading Business in March 2001.
(2) Reflects the adoption of Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging
Activities" on January 1, 2001.
(3) Reflects the acquisition of the Midwest Assets in May 2001.
-11-
RISK FACTORS
RISKS RELATED TO OUR BUSINESS OPERATIONS
CHANGES IN COMMODITY PRICES MAY INCREASE OUR COST OF PRODUCING POWER OR DECREASE
THE AMOUNT WE RECEIVE FROM SELLING POWER, ADVERSELY AFFECTING OUR FINANCIAL
PERFORMANCE.
We are heavily exposed to changes in the price and availability of coal
because most of our generating capacity is coal-fired. We have long-term
contracts for the supply of coal for most of our existing generation capacity,
but many of these contracts are nearing the end of their term and we may not be
able to purchase coal on terms as favorable as the current contracts.
We are diversifying our dependence on coal-fired facilities through the
acquisition and construction of natural gas-fired facilities which increases our
exposure to the more volatile market prices of natural gas. Almost all of our
announced construction and development plans for additional generating capacity
have involved natural gas-fired facilities.
Changes in the cost of coal or natural gas and changes in the
relationship between those costs and the market prices of electricity will
affect our financial results. Since the price we obtain for electricity may not
change at the same rate as the change in coal or natural gas costs, we may be
unable to pass on the changes in costs to our customers.
In addition, actual power prices and fuel costs will differ from those
assumed in financial models, and those differences may be material. As a result,
our financial results may not meet our expectations.
WE MAY NOT ALWAYS FULLY HEDGE AGAINST CHANGES IN COMMODITY PRICES.
To manage our financial exposure to commodity price fluctuations, we
routinely enter into contracts, such as electricity and natural gas purchase and
sale commitments, to hedge our exposure to fuel supply and demand, market
effects due to weather and other energy-related commodities. However, we do not
necessarily 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 ENERGY TRADING, FUEL PROCUREMENT, POWER MARKETING AND RISK MANAGEMENT
POLICIES MAY NOT WORK AS PLANNED.
Our energy trading, fuel procurement, power marketing and risk
management procedures may not always be followed or may not work as planned. As
a result, we cannot predict the impact that our energy trading, fuel
procurement, power marketing and risk management decisions may have on our
business, operating results or financial position.
Our energy trading, fuel procurement, power marketing and risk
management activities, including our power sales agreements with counterparties,
rely on models that depend heavily on judgments and assumptions by management of
factors such as the future market prices and demand for electricity and other
energy-related commodities. These factors become more difficult to predict and
the models become less reliable the further into the future these estimates are
made. Even when our policies and procedures are followed and decisions are made
based on these models, there may nevertheless be an adverse impact on our
financial position and results of operations, if the judgments and assumptions
underlying those models prove to be wrong or inaccurate.
PARTIES WITH WHOM WE HAVE CONTRACTS MAY FAIL TO PERFORM THEIR OBLIGATIONS, WHICH
COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
We purchase coal from a limited number of suppliers. In 2000, we
purchased approximately 60% of our fuel, primarily coal, from one supplier. Any
disruption in the delivery of coal, including disruptions as a result of
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weather, labor relations or environmental regulations affecting our coal
suppliers, could adversely affect our ability to operate our coal-fired
facilities and thus our results of operations.
Delivery of natural gas to each of our natural gas-fired facilities
typically depends on the natural gas pipeline or distributor for that location.
As a result, we are subject to the risk that a natural gas pipeline or
distributor may suffer disruptions or curtailments in its ability to deliver
natural gas to us or that the amounts of natural gas we request are curtailed.
These disruptions or curtailments could adversely affect our ability to operate
natural gas-fired generating facilities and thus our results of operations.
In addition, we are exposed to the risk that counterparties that owe us
money or energy will breach their obligations. Should the counterparties to
these arrangements fail to perform, we may be forced to enter into alternative
hedging arrangements or honor the underlying commitment at then-current market
prices. In that event, our financial results are likely to be adversely affected
and we might incur losses. Although our models take into account the expected
probability of default by a counterparty, our actual exposure to a default by a
counterparty may be greater than the models predict.
A BREACH OR A RENEGOTIATION OF OUR POWER SALES AGREEMENT WITH THE CALIFORNIA
DEPARTMENT OF WATER RESOURCES MAY HAVE A MATERIAL IMPACT ON OUR RESULTS OF
OPERATIONS.
Various parties have publicly urged the State of California to
renegotiate power sales agreements between the California Department of Water
Resources and suppliers of electricity, including us, on the grounds that the
Department is paying too high a price for too much power for too long a period.
Our agreement with the Department is recorded on our balance sheet as an asset
at the fair value of the contract. If our agreement were renegotiated or if the
Department failed for any reason to meet its obligations under this agreement,
the value of the agreement as an asset might need to be reduced on our balance
sheet, with a corresponding charge reducing net income.
OUR POWER GENERATION FACILITIES MAY PERFORM BELOW EXPECTATIONS, REQUIRE COSTLY
REPAIRS OR REQUIRE US TO PURCHASE REPLACEMENT POWER.
The operation of power generation facilities involves many risks,
including the breakdown or failure of electrical generating or other equipment,
fuel interruption and performance below expected levels of output or efficiency.
In addition, weather-related incidents and other natural disasters can disrupt
generation facilities. If our facilities operate below expectations, we may lose
revenues or have increased expenses, including replacement power costs. A
significant portion of our facilities were constructed many years ago. Older
generating equipment, even if maintained in accordance with good engineering
practices, may require significant capital expenditures on our part to keep
operating at peak efficiency and is also likely to require periodic upgrading
and improvement.
WE HAVE ONLY A LIMITED OPERATING HISTORY IN A MARKET-BASED COMPETITIVE
ENVIRONMENT.
The facilities that were transferred to us by Allegheny Energy's
regulated utility subsidiaries 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 do not benefit from predetermined rates that include a rate of
return component. Also, 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
and ancillary services. We have a limited operating history for these facilities
in a market-based competitive environment, and we may not be able to operate
them successfully in such an environment.
WE RELY ON POWER TRANSMISSION FACILITIES THAT WE DO NOT OWN OR CONTROL. IF THESE
FACILITIES DO NOT PROVIDE US WITH ADEQUATE TRANSMISSION CAPACITY, WE MAY NOT BE
ABLE TO DELIVER OUR WHOLESALE ELECTRIC POWER TO OUR CUSTOMERS.
We depend on transmission and distribution facilities owned and operated
by utilities and other power companies to deliver the electricity we sell. This
dependence exposes us to a variety of risks. If transmission is disrupted, or
transmission capacity is inadequate, we may not be able to sell and deliver our
products. If a region's
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power transmission infrastructure is inadequate, our recovery of costs and
profits may be limited. If restrictive transmission price regulation is imposed,
the transmission companies may not have sufficient incentive to invest in
expansion of transmission infrastructure.
The Federal Energy Regulatory Commission, or FERC, has issued power and
gas transmission initiatives that require electric and gas transmission services
to be offered unbundled from commodity sales. Although these initiatives are
designed to encourage wholesale market transactions for electricity and gas,
fair and equal access to transmission systems may in fact not be available. We
cannot predict the timing or scope of the industry response to these
initiatives. We also cannot predict whether transmission facilities will be
expanded in specific markets as required by these initiatives.
CHANGES IN TECHNOLOGY MAY SIGNIFICANTLY AFFECT OUR BUSINESS BY MAKING OUR POWER
PLANTS LESS COMPETITIVE.
A key element of our business model is that generating power at central
power plants achieves economies of scale and produces electricity at relatively
low cost. There are other technologies that produce electricity, most notably
fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is
possible that advances in technology will reduce the cost of alternative methods
of producing electricity to a level that is competitive with that of most
central power station electric production. If this were to happen and if these
technologies achieved economies of scale, our market share could be eroded, and
the value of our power plants could be significantly impaired. Changes in
technology could also alter the channels through which retail electric customers
buy electricity, thereby affecting our financial results.
OUR OPERATING RESULTS MAY FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS.
Electrical power generation is generally a seasonal business. In many
parts of the country, demand for electricity peaks during the hot summer months,
with market prices also peaking at that time. 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
facilities we acquire and the terms of power sale contracts we enter into.
THE LOSS OF OUR KEY EXECUTIVES OR OUR FAILURE TO ATTRACT QUALIFIED MANAGEMENT
COULD LIMIT OUR GROWTH AND NEGATIVELY AFFECT OUR OPERATIONS.
The success of our business relies, in large part, on our ability to
attract and retain talented employees who possess the experience and expertise
required to manage our business and its growth successfully. Our current key
executives have substantial experience in our industry. The unexpected loss of
services of one or more of these individuals could adversely affect us.
Likewise, our inability to attract employees of a similar caliber in the future
could have a material negative impact on our plans for continued growth and
business success.
OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT, AND THE COST OF
COMPLIANCE WITH FUTURE ENVIRONMENTAL LAWS COULD ADVERSELY AFFECT OUR CASH FLOW
AND PROFITABILITY.
Our operations are subject to extensive federal, state and local
environmental statutes, rules and regulations relating to air quality, water
quality, waste management, natural resources and health and safety. Compliance
with these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment, emission
fees and permits at all of our facilities. These expenditures have been
significant in the past and we expect that they will increase in the future.
Costs of compliance with environmental regulations, and in particular emission
regulations, could have a material impact on our industry, our business and our
results of operations and financial position, especially if emission limits are
tightened, more extensive permitting requirements are imposed, additional
substances become regulated, and the number and types of assets we operate
increase.
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WE ANTICIPATE THAT WE WILL INCUR CONSIDERABLE CAPITAL COSTS FOR COMPLIANCE.
We plan to install new emissions control equipment and may be required
to upgrade existing equipment, purchase emissions allowances or reduce
operations. During the period 2002 through 2004, we expect to spend
approximately $162.3 million in connection with the installation of emission
control equipment at our facilities. This amount does not include expenditures
relating to the remaining generating assets that we expect to have transferred
to us from one of Allegheny Energy's regulated utility subsidiaries, Monongahela
Power. The expected expenditures for the installation of emission control
equipment at these Monongahela Power facilities would be $64.2 million for the
same period. Moreover, environmental laws are subject to change, which may
materially increase our costs of compliance or accelerate the timing of these
capital expenditures.
WE MAY EXPERIENCE SHUT DOWNS IF WE ARE UNABLE TO OBTAIN ALL REQUIRED
ENVIRONMENTAL APPROVALS.
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 or comply with any
such approval, the affected facilities could be delayed in becoming operational,
temporarily closed 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 lead us to shut down or reduce the operations at certain
individual generating units.
CHANGES IN LAWS AND REGULATIONS COULD APPLY TO US.
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 nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions from
coal-burning plants are being re-interpreted by federal and state authorities.
These re-interpretations could result in limitations on these emissions
substantially more stringent 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.
In addition, the Environmental Protection Agency is developing new
policies concerning protection of endangered species and sediment contamination,
based on a new interpretation of the Clean Water Act. The scope and extent of
any resulting environmental regulations, and their effect on our operations, are
unclear.
GOVERNMENTAL AUTHORITIES MAY ASSESS PENALTIES ON US FOR FAILURES TO COMPLY
WITH ENVIRONMENTAL LAWS AND REGULATIONS.
If we fail to comply with environmental laws and regulations, even if
caused by factors beyond our control, our failure may result in the assessment
of civil or criminal liability and fines against us. Recent lawsuits by the
Environmental Protection Agency and various states highlight the environmental
risks faced by generating facilities, in general, and coal-fired generating
facilities, in particular. For example, the Attorneys General of New York and
Connecticut notified us in 1999 of their intent to commence civil actions
against us for alleged violations of the Clean Air Act Amendments. If these
actions were filed and if they were resolved against us, substantial
modifications of our existing coal-fired power plants would be required. Similar
actions may be commenced by other governmental authorities in the future.
In addition, a number of our coal-fired facilities have been the subject
of a formal request for information from the Environmental Protection Agency. If
an enforcement proceeding or litigation in connection with this request, or in
connection with any proceeding for non-compliance with environmental laws, were
commenced and resolved against us, we could be required to invest significantly
in new emission control equipment, accelerate the timing of capital
expenditures, pay penalties and/or halt operations. Moreover, our results of
operations and financial position could suffer due to the consequent distraction
of management and the expense of ongoing litigation. Other parties have settled
similar lawsuits.
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WE ARE UNLIKELY TO BE ABLE TO PASS ON THE COST OF ENVIRONMENTAL COMPLIANCE
TO OUR CUSTOMERS.
Most of our contracts with customers and, except to a limited extent,
the power sales agreements with the regulated utility subsidiaries of Allegheny
Energy, do not permit us to recover additional capital and other costs incurred
by us to comply with new environmental regulations. As a result, to the extent
these costs are incurred prior to the expiration of these contracts, these costs
could adversely affect our profitability.
WE MAY BECOME SUBJECT TO LEGAL CLAIMS ARISING FROM THE USE OF ASBESTOS OR OTHER
HAZARDOUS SUBSTANCES AT OUR GENERATING FACILITIES.
Although we did not assume any liabilities for asbestos claims or any
other environmental claims when the generating assets were transferred to us by
the regulated utility subsidiaries of Allegheny Energy, we may be named as a
co-defendant with the regulated utility subsidiaries in pending asbestos claims
involving multiple plaintiffs. We believe that we use and store all hazardous
substances in a safe and lawful manner. However, asbestos and other hazardous
substances are currently used and may in the future continue to be used at our
facilities which could result in claims being brought against us involving
exposure to asbestos or other hazardous substances.
RISKS ASSOCIATED WITH OUR ACQUISITION AND DEVELOPMENT ACTIVITIES
OUR ACQUISITION OF GENERATING FACILITIES AND DEVELOPMENT ACTIVITIES MAY NOT BE
SUCCESSFUL, WHICH WOULD IMPAIR OUR ABILITY TO GROW PROFITABLY.
OUR GROWTH STRATEGY REQUIRES US TO IDENTIFY AND COMPLETE DEVELOPMENT
PROJECTS.
Our strategy for the growth of our business depends on our ability to
identify and complete acquisition, development and construction projects at
appropriate prices. If the assumptions underlying the prices we pay for future
acquisitions, development and construction projects prove to be inaccurate, the
financial performance of the particular facility and our overall results of
operations and financial position could be significantly adversely affected.
Moreover, if we are not able to access capital at competitive rates, our growth
will be adversely affected. A number of factors could affect our ability to
access capital, including general economic conditions, capital market
conditions, market prices for electricity and gas and the overall health of the
utility industry, our capital structure as a subsidiary of Allegheny Energy and
limitations imposed by the Public Utility Holding Company Act of 1935.
WE WILL BE REQUIRED TO SPEND SIGNIFICANT SUMS BEFORE ACQUISITION OR
CONSTRUCTION OF A FACILITY.
Before we can acquire a generation facility or commence construction, we
may be required to invest significant resources on preliminary engineering,
permitting, legal and other matters in order to determine the feasibility of the
project. Moreover, the process for obtaining initial environmental, siting and
other governmental and regulatory permits and approvals is complicated,
expensive and lengthy, and is subject to significant uncertainties. We may also
be required to obtain SEC approval for our financing arrangements. Obtaining
these permits and approvals can delay acquisition and construction. If for any
reason we are not able to obtain all required permits and approvals, or obtain
them in a timely manner, we may be prevented from completing an acquisition,
development or construction project. We also may not be able to obtain and
comply with all necessary licenses, permits and approvals for our existing
facilities that we seek to expand.
PLANT CONSTRUCTION IS COSTLY AND SUBJECT TO NUMEROUS RISKS.
We have announced construction plans for five generating facilities
totaling approximately 2,382 MW, and we intend to pursue our strategy of
developing and constructing other new facilities and expanding existing
facilities. Our completion of these facilities without delays or cost overruns
is subject to substantial risks, including:
o shortages and inconsistent quality of equipment, material and
labor;
o work stoppages;
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o permits, approvals and other regulatory matters;
o adverse weather conditions;
o unforeseen engineering problems;
o environmental and geological conditions;
o unanticipated cost increases; and
o our attention to other projects.
If we are unable to complete the development or construction of a
facility, we may not be able to recover our investment in it. In addition,
construction delays and contractor performance shortfalls can result in the loss
of revenues and may, in turn, adversely affect our results of operations and
financial position. Furthermore, if construction projects are not completed
according to specifications, we may incur liabilities, and suffer reduced plant
efficiency, higher operating costs and reduced earnings. Also, changes in market
prices for electricity from these projects may not make it cost effective to
complete these projects.
SOME RISKS CANNOT BE COVERED BY INSURANCE.
While we maintain insurance, obtain warranties from vendors and obligate
contractors to meet specified performance standards, we remain substantially
exposed to the risks described above. Furthermore, the proceeds of such
insurance and the warranties or performance guarantees may not be adequate to
cover lost revenues, increased expenses or liquidated damages payments that we
may owe upon the realization of any of the risks described above.
THERE IS UNCERTAINTY ABOUT WHEN, IF AT ALL, THE WEST VIRGINIA JURISDICTIONAL
GENERATING ASSETS OF MONONGAHELA POWER WILL BE TRANSFERRED TO US.
It is our goal to have the West Virginia jurisdictional generating
assets of Monongahela Power, representing approximately 2,111 MW of capacity,
transferred to us. We are currently exploring ways to effect the transfer of
these generating assets to us, including by regulatory action or by legislation
in next year's session of the West Virginia Legislature. Monongahela Power has
filed a petition seeking the West Virginia Public Service Commission's approval
of the transfer of the West Virginia jurisdictional generating assets to us. The
West Virginia Public Service Commission has not yet acted on this petition, and
we cannot assure you that it will permit the transfer, or when this permission
might be granted. If the transfer is permitted, we cannot predict the conditions
that may be imposed upon us in connection with it, such as the terms under any
long-term power sales agreement necessary to meet Monongahela Power's
provider-of-last-resort retail load obligations, transfer costs or transition
periods, any of which may make the transfer uneconomical.
IT MAY BE DIFFICULT FOR INVESTORS TO EVALUATE THE PROBABLE IMPACT OF OUR
ACQUISITIONS AND TRANSFERS OF GENERATING ASSETS ON OUR FINANCIAL PERFORMANCE.
Because of the high levels of acquisition and transfer activity since
our formation in November 1999, it may be difficult for investors to evaluate
the probable impact of these acquisitions and generating asset transfers on our
financial performance or make meaningful comparisons between reporting periods
until we have operating results for a number of reporting periods for these
facilities and assets. For instance, for the period October 1, 2000 through
September 30, 2001, we increased our ownership of and contractual control of
generating capacity to 9,796 MW from 6,356 MW owned or under contractual control
as of September 30, 2000. Similarly, we expect this will be an issue for the
next few years as we add 4,891 MW of additional capacity.
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WE HAVE MADE OR HAVE COMMITTED SUBSTANTIAL INVESTMENTS IN OUR RECENT
ACQUISITIONS, DEVELOPMENT AND CONSTRUCTION PROJECTS, AND OUR SUCCESS DEPENDS ON
OUR ABILITY TO SUCCESSFULLY INTEGRATE, OPERATE AND MANAGE THESE ASSETS.
Since our formation, we have received transfers of 6,230 MW of
generating assets from Allegheny Energy's regulated utility subsidiaries and
have acquired or announced the addition of a further 8,457 MW of generation
capacity, including the pending transfer of 2,160 MW from Allegheny Energy and
its subsidiaries. We cannot assure you that these facilities will generate cash
flows or revenue that provide appropriate returns on our investments or that we
will successfully:
o integrate the assets that we have acquired, and any we acquire in
the future, with our existing operations;
o develop our management and corporate infrastructure;
o negotiate favorable terms for the sale of electricity generated
by our recently acquired facilities, those we plan to construct
or develop and any we acquire in the future; or
o operate our recently acquired facilities, and any we acquire in
the future, on an efficient, cost-effective basis.
Our ability to successfully integrate assets will depend on, among other
things, the adequacy of our implementation plans, the ability to achieve desired
operating efficiencies, and favorable terms for the electricity that we
generate. If we are unable to successfully integrate these assets into our
operations, we could experience increased costs and losses on our investments.
WE MAY BE REQUIRED TO ASSUME LIABILITIES, INCLUDING ENVIRONMENTAL AND
EMPLOYEE-RELATED LIABILITIES, UNDER ACQUISITION AGREEMENTS.
Some of the acquisition agreements that we have entered into with third
parties have required that we assume specified pre-closing liabilities,
primarily related to environmental and employee matters. We are likely to be
required to assume these types of liabilities, as well as others, in connection
with future acquisitions. As a result, we may be liable for significant
environmental remediation costs and other liabilities arising from the operation
of our facilities by prior owners, which could have a significant adverse effect
on our cash flow and results of operations.
RISKS ASSOCIATED WITH REGULATION
THE REGULATED UTILITY SUBSIDIARIES OF ALLEGHENY ENERGY HAVE
"PROVIDER-OF-LAST-RESORT" OBLIGATIONS. WE HAVE AGREED TO PROVIDE ELECTRICITY TO
THE REGULATED UTILITY SUBSIDIARIES IN AMOUNTS SUFFICIENT TO SATISFY THESE
OBLIGATIONS AT PRICES WHICH MAY BE BELOW OUR COST AND IN AMOUNTS THAT MAY EXCEED
OUR SUPPLY CAPACITY.
OUR OBLIGATIONS TO PROVIDE POWER UNDER POWER SALES AGREEMENTS MAY HAVE NO
RELATIONSHIP TO OUR ACTUAL COST TO SUPPLY THIS POWER.
As part of restructuring initiatives, Allegheny Energy's regulated
utility subsidiaries have been designated during a transition period as the
"provider-of-last-resort" to all customers that do not choose an alternate
supplier of electricity and to customers that switch back from alternate
suppliers. To satisfy this obligation, the regulated utility subsidiaries source
this power from us under long-term power sales agreements. These power sales
agreements currently require a significant portion of the normal operating
capacity of our fleet of transferred generating assets. The prices we receive
may have little or no relationship to the cost to us of supplying this power
under these agreements. This means that we are limited in our ability to pass on
to the regulated utility subsidiaries of Allegheny Energy the risk of fuel price
increases and increased costs of environmental compliance. We expect that there
will be similar risks when customer choice is implemented in West Virginia, a
state in which Monongahela Power has distribution operations.
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DEMAND FOR OUR POWER MAY EXCEED OUR SUPPLY CAPACITY.
From time to time the demand for power required to meet the
provider-of-last-resort obligations could exceed our generating facilities'
available capacity. A variety of factors may cause such a situation, including
an increase in the number of customers of Allegheny Energy's regulated utility
subsidiaries, greater demand for power from existing customers or an
interruption of service at our generating facilities. If this obligation exceeds
our own energy production levels, we would have to buy additional power on the
market. Since these situations most often occur during periods of peak demand,
it is likely that the market price for power at such times would be very high.
Even if our supply shortage were brief, we could suffer substantial losses that
could have an adverse affect on our results of operations.
THE PROVIDER-OF-LAST-RESORT OBLIGATIONS DO NOT RESTRICT CUSTOMERS FROM
SWITCHING SUPPLIERS OF POWER.
The power sales agreements with the regulated utility subsidiaries to
meet their provider-of-last-resort obligations do not provide us with any
guaranteed level of power sales. If the customers of the regulated utility
subsidiaries obtain service from alternative suppliers, which they are entitled
to do at any time, our sales of power may decrease. Alternatively, customers
could switch back to the regulated utility subsidiaries from alternative
suppliers, which may increase demand above our facilities' available capacity,
some of which we may have committed to sell to other customers. Thus, any such
switching by customers could have an adverse affect on our results of operations
and financial position.
OUR BUSINESS OPERATES IN THE 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 POWER INDUSTRY
IS REVERSED, DISCONTINUED OR DELAYED, OUR BUSINESS PROSPECTS AND FINANCIAL
CONDITION COULD BE MATERIALLY ADVERSELY AFFECTED.
The regulatory environment of 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.
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 markets, such as in
California, have experienced interruptions of supply and price volatility. These
interruptions of supply and price volatility have been the subject of a
significant amount of press coverage, much of which has been critical of the
restructuring initiatives. In some of these markets, including California,
government agencies and other interested parties have made proposals to
re-regulate areas of these markets that have previously been deregulated, and,
in California, legislation has been passed placing a moratorium on the sale of
generating plants by regulated utilities. Proposals to re-regulate the wholesale
power market also have been made at the federal level. Proposals of this sort,
and legislative or other attention to the electric restructuring process in
states in which we currently, or may in the future, operate, may cause this
process to be delayed, discontinued or reversed, which could have a material
adverse effect on our results of operations or our strategies.
WE MAY NOT BE ABLE TO RESPOND EFFECTIVELY TO COMPETITION.
We may not be able to respond in a timely or effective manner to the
many changes in the power industry that may occur as a result of regulatory
initiatives to increase competition. These regulatory initiatives may include
deregulation of the electric utility industry in some markets and privatization
of the electric utility industry in others. To the extent that competition
increases, our profit margins may be negatively affected. Industry deregulation
and privatization may not only continue to facilitate the current trend toward
consolidation in the utility industry but may also encourage the disaggregation
of other vertically integrated utilities into separate generation, transmission
and distribution businesses. As a result, additional competitors in our industry
may be created, and we may not be able to maintain our revenues and earnings
levels or pursue our growth strategy.
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While demand for electric energy services is generally increasing
throughout the United States, the rate of construction and development of new,
more efficient electric generation facilities may exceed increases in demand in
some regional electric markets. The start-up of new facilities in the regional
markets in which we have facilities could increase competition in the wholesale
power market in those regions, which could have a material negative effect on
our business, results of operations and financial condition. Also, industry
restructuring in regions in which we have substantial operations could affect
our operations in a manner that is difficult to predict, since the effects will
depend on the form and timing of the restructuring.
THE DIFFERENT REGIONAL POWER MARKETS IN WHICH WE COMPETE OR WILL COMPETE IN THE
FUTURE HAVE CHANGING REGULATORY STRUCTURES, WHICH COULD AFFECT OUR PERFORMANCE
IN THESE REGIONS.
Our results are likely to be affected by differences in the market and
regulatory structures in various regional power markets. Problems that may arise
in the formation and operation of new regional transmission organizations, or
"RTOs", such as the proposed new RTO extending across the entire Northeastern
region of the United States, may result in delayed or disputed collection of
revenues. The rules governing the various regional power markets may also change
from time to time which could affect our costs or revenues. Because it remains
unclear which companies will be participating in the various regional power
markets, or how RTOs will develop or what regions they will cover, we are unable
to assess fully the impact that these power markets may have on our business.
Our operating results will also be affected by the addition of generation or
transmission capacity serving the PJM-West and any other power markets.
OUR BUSINESS WILL CONTINUE TO BE SUBJECT TO REGULATION UNDER THE PUBLIC UTILITY
HOLDING COMPANY ACT SO LONG AS WE ARE A SUBSIDIARY OF ALLEGHENY ENERGY. THAT ACT
LIMITS OUR BUSINESS OPERATIONS, OUR ABILITY TO RECEIVE DIVIDENDS FROM OUR
SUBSIDIARIES AND OUR ABILITY TO AFFILIATE WITH PUBLIC UTILITIES.
So long as Allegheny Energy owns at least 10% of our voting securities,
we will continue to be subject to regulation under the Public Utility Holding
Company Act, or PUHCA, as a subsidiary of a public utility holding company
registered under PUHCA. PUHCA limits our ability to acquire, own and operate
energy assets outside of our current business plan and it limits the dividends
that our subsidiaries may pay from unearned surplus. In addition, as long as we
are an affiliate of Allegheny Energy, we must obtain prior approval under PUHCA
in order to raise financing or to acquire the voting securities of any public
utility or take any other action that would result in our affiliation with
another public utility.
We have submitted an application to the SEC under PUHCA requesting an
increase in our authority to acquire, own and operate exempt wholesale
generators. If the SEC does not grant this authority, our operations may be
adversely affected, and it may limit our ability to pursue our current business
strategies.
SOME LAWS AND REGULATIONS GOVERNING RESTRUCTURING OF THE WHOLESALE GENERATION
MARKET IN VIRGINIA AND WEST VIRGINIA HAVE NOT YET BEEN INTERPRETED OR ADOPTED
AND COULD HAVE A MATERIAL NEGATIVE IMPACT ON OUR BUSINESS, OPERATING RESULTS AND
FINANCIAL CONDITION.
While the electric restructuring laws in Virginia and West Virginia
established the general framework governing the retail electric market, the laws
required the utility commission in each state to issue rules and determinations
implementing the laws. Some of the regulations governing the retail electric
market have not yet been adopted by the utility commission in each state. These
laws, when they are interpreted and when the regulations are developed and
adopted, may have a negative impact on our business, results of operations and
financial condition.
RISKS ASSOCIATED WITH OUR FINANCING AND CAPITAL STRUCTURE
WE WILL HAVE SUBSTANTIAL INDEBTEDNESS, WHICH COULD RESTRICT OUR ACTIVITIES AND
COULD AFFECT OUR ABILITY TO MEET OUR OBLIGATIONS.
We incurred substantial indebtedness to finance our acquisitions of the
Energy Trading Business and the Midwest Assets. We anticipate incurring further
substantial indebtedness to support future acquisitions and capital
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expenditures, and maintain working capital. We had, as of September 30, 2001,
total indebtedness of approximately $2.34 billion.
Future indebtedness may be on terms that are more restrictive or
burdensome than our current indebtedness. This may negatively affect our ability
to operate our business and have a material adverse effect on our ability to
acquire, construct or develop new facilities.
Our level of indebtedness may have important consequences, including:
o making it more difficult for us to satisfy our obligations under
the old notes and new notes;
o limiting our ability to borrow additional amounts for capital
expenditures, future acquisitions, significant working capital
requirements to conduct our wholesale marketing, energy trading
and fuel procurement activities as well as for other corporate
purposes;
o limiting our ability to use operating cash flow in other areas of
our business, such as for capital expenditures and future
acquisitions, because we must dedicate a substantial portion of
these funds to service our debt;
o limiting our ability to capitalize on business opportunities and
to react to competitive pressures and adverse changes in
government regulation, including increasingly stringent
environmental regulation; and
o subjecting us to financial and other restrictive covenants with
which we may fail to comply, which could result in an event of
default.
Our ability to meet our payment obligations under our indebtedness,
including the old notes and new notes, and to fund capital expenditures will
depend on our future performance. Our future performance is subject to
regulatory, economic, financial, competitive, legislative and other factors that
are beyond our control and are discussed elsewhere in these risk factors. Our
cash flow from operations may not be sufficient to meet all of our payment
obligations under our debt, including the old notes and new notes, or to fund
our other liquidity needs.
YOU CANNOT BE SURE THAT AN ACTIVE TRADING MARKET WILL DEVELOP FOR THE NEW NOTES.
The new notes are a new issue of securities with no established trading
market and will not be listed on any securities exchange. The initial purchasers
may cease their market-making at any time. In addition, such market-making
activity may be limited during the pendency of the exchange offer or the
effectiveness of a shelf registration statement in lieu of the exchange offer.
Although under the registration rights agreement, we are required to use our
reasonable best efforts to commence the exchange offer to exchange the old notes
for the new notes, or to register resales of the old notes under the Securities
Act, we cannot assure you that an active trading market for the old notes or any
new notes exchanged for the old notes will develop.
ANY DECREASE IN ALLEGHENY ENERGY'S OWNERSHIP IN US MAY ADVERSELY AFFECT OUR
CREDIT RATING AND OUR ABILITY TO OBTAIN THIRD PARTY FINANCING.
Allegheny Energy has announced that it is seeking authorization to
effect an initial public offering of the common stock of our proposed new parent
holding company into which we will be merged and distribute the remaining common
stock of that new holding company to Allegheny Energy's shareholders. An initial
public offering and spin-off could negatively affect our credit rating and our
ability to obtain financing. To date, we have obtained third-party financing on
relatively favorable terms based, in part, on Allegheny Energy's ownership
interest in us. If Allegheny Energy reduces its ownership in us, we may not be
able to obtain third-party financing on terms that are as favorable as we have
experienced in the past. Also, if Allegheny Energy disposes of its ownership in
us, we intend to no longer be regulated under the PUHCA. If this should occur,
certain restrictions, such as minimum equity to capitalization ratios, designed
to safeguard investors, will no longer apply to us.
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FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements, including
statements regarding our results of operations, assets and liabilities and
statements with respect to deregulation activities, movements towards
competition in states that are served by our operations, markets, products,
services, prices, generating capacity, provider-of-last-resort contract
obligations, capital expenditures, resolution and impact of litigation,
regulatory matters, liquidity, capital resources and accounting matters. You can
typically identify forward-looking statements by the use of forward-looking
words, such as "may," "will," "could," "project," "projection," "believe,"
"anticipate," "expect," "intend," "estimate," "continue," "potential," "plan,"
"forecast," "strategy" and the like. We cannot assure you that our actual
results will not differ materially from expectations or estimates. Actual
results have varied materially and unpredictably from past expectations and
estimates. Factors that could cause our actual results to differ materially
include those discussed under "RISK FACTORS" as well as:
o the weather and other natural phenomena;
o political, economic and business conditions, including the
continuing impact on the economy of the September 11, 2001
terrorist attacks;
o growth in industry capacity;
o separation of the operations of Allegheny Energy;
o regulatory developments;
o loss of any significant customers or suppliers;
o changes in business strategy or business plans;
o changes in technology;
o litigation; and
o the effect of accounting policies issued periodically by
accounting standard-setting bodies.
USE OF PROCEEDS
We will not receive any proceeds from the exchange offer. In
consideration for issuing the new notes, we will receive old notes from you in
the same principal amount. The old notes surrendered in exchange for the new
notes will be retired and canceled and cannot be reissued. Accordingly, issuance
of the new notes will not result in any change in our indebtedness.
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RATIO OF EARNINGS TO FIXED CHARGES
The following table sets forth the ratio of earnings to fixed charges for us for
each of the periods indicated:
From November 18
Nine Months Ended Twelve Months Ended Year Ended Inception Date Through
September 30, 2001(1) September 30, 2001(1) December 31, 2000(1) December 31, 1999(1)
--------------------- --------------------- -------------------- ---------------------
5.34 5.23 3.82 5.97
- --------------------
(1) The ratio of earnings to fixed charges is calculated by dividing
earnings by fixed charges.
Earnings means net income from continuing operations before
adjustment for minority interest in consolidated subsidiaries and
income from equity investees, plus fixed charges, plus income taxes,
plus amortization of capitalized interest, plus distributed income
of equity investees, less interest capitalized.
Fixed charges means interest expenses, plus interest capitalized,
plus amortization of debt issuance costs, plus estimated interest
component of rental expense.
CAPITALIZATION AND SHORT-TERM DEBT
The following table sets forth our short-term debt and capitalization as
of September 30, 2001.
September 30, 2001
----------------------
(Dollars in Thousands)
Short-term debt and notes payable to parent and affiliates $1,366,052 35%
Capitalization:
Long-term debt due within one year 83,507 2
Long-term debt 892,714 23
Minority interest 30,912 1
Members' equity 1,520,448 39
Total capitalization ------------ ----------
$2,527,581 65
------------ ----------
Total capitalization and short-term debt $3,893,633 100%
============ ==========
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
We are a rapidly growing merchant energy company with 14,687 megawatts,
or MW, of generating capacity owned, controlled, under construction or in
development, pending transfer from affiliates or planned as facility expansions.
We currently own or have the contractual right to control 9,796 MW in
California, Indiana, Illinois, Maryland, Ohio, Pennsylvania, Tennessee, Virginia
and West Virginia. 6,230 MW of this capacity was transferred from West Penn,
Potomac Edison and Monongahela Power at net book value. West Penn, Potomac
Edison and Monongahela Power are all regulated utility subsidiaries of our
parent company, Allegheny Energy. It is our goal to complete the transfer of an
additional 2,111 MW of generating capacity from Monongahela Power. Our strategy
is to expand our generation fleet of 9,796 MW by a further 4,891 MW through the
announced construction and development of new facilities, acquisition of
contractual rights to control generating capacity, planned expansions to
existing facilities and pending transfers of generating capacity from
Monongahela Power and other Allegheny Energy subsidiaries. This additional
generation capacity will be located in the states of Arizona, Indiana, Nevada,
New York, Ohio, Pennsylvania, Virginia and West Virginia.
We manage all of our generation assets as an integrated portfolio with
our energy trading, fuel procurement, power marketing and risk management
activities of our wholly-owned subsidiary, Allegheny Energy Global Markets.
In 1999, our company, then a wholly-owned subsidiary of Allegheny
Energy, was formed in order to consolidate Allegheny Energy's deregulated
generating assets into a single company that is not subject to state regulation
of sales prices. Today, Allegheny Energy continues to have approximately a 98%
ownership interest in us.
The table below summarizes the electric generating capacity which we own
or contractually control; which we are awaiting transfer from the regulated
subsidiaries of Allegheny Energy or its unregulated affiliates; and for which we
announced construction and development plans, contractual control of generating
capacity and planned expansions to existing facilities as of November 30, 2001:
CAPACITY (MW)
Company-owned and contractually controlled generation 9,796
Affiliate generation pending transfer 2,160
Announced construction and development, contractual
control and planned expansions 2,731
------
Total 14,687
======
SIGNIFICANT EVENTS
CORPORATE RESTRUCTURING
In November 2001, we and our parent, Allegheny Energy, filed an
application with the SEC seeking authorization under the Public Utility Holding
Company Act of 1935 to restructure our corporate organization by creating a new
Maryland holding company into which we will then merge. We will thereby be
changed from a Delaware limited liability company into a Maryland corporation.
We and our parent, Allegheny Energy, also sought authorization to merge
Allegheny Energy Global Markets, one of our wholly-owned subsidiaries, into this
new Maryland holding company, which will then continue to conduct the energy
commodity marketing and trading activities of Allegheny Energy Global Markets.
On December 31, 2001, we received SEC approval to effect this reorganization.
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PROPOSED IPO AND DISTRIBUTION
On July 23, 2001, we, together with Allegheny Energy and other
affiliates, filed a U-1 application with the SEC, seeking authorization under
the Public Utility Holding Company Act of 1935, or PUHCA, to, among other
things:
o effect an initial public offering of up to 18% of the common
stock of the new Maryland holding company, which we intend to
complete when favorable and other market conditions exist;
o implement an employee stock option plan for us, and issue options
to satisfy contractual obligations; and
o distribute the remaining common stock of the new Maryland holding
company owned by Allegheny Energy and not sold in the initial
public offering to the stockholders of Allegheny Energy on a
tax-free basis within 24 months following completion of the
initial public offering.
The purpose of the initial public offering and distribution is to permit
us and Allegheny Energy's regulated utility operations to focus on our
respective businesses and market opportunities and, in particular, to allow us
to pursue our growth strategy for our electric generation business. The initial
public offering and the distribution of Allegheny Energy's remaining equity
ownership of the new holding company are subject to market and other conditions.
The corporate restructuring, initial public offering and distribution
would create two independent companies:
o A new Maryland holding company described above that will own our
generation business and operate the assets of this business as an
integral part of the energy trading, fuel procurement, power
marketing and risk management activities of the Allegheny Energy
Global Markets business; and
o Allegheny Energy which will include its regulated utility
operating subsidiaries, West Penn, Potomac Edison and Monongahela
Power, doing business as Allegheny Power, as well as another
subsidiary, Allegheny Ventures, Inc. Allegheny Power is a
diversified energy and energy services company that delivers
electric energy and natural gas to approximately three million
people in parts of Maryland, Ohio, Pennsylvania, Virginia, and
West Virginia. Allegheny Ventures, Inc. is a growing business
development company that invests in and develops
telecommunications and energy-related projects.
The filing of the U-1 application is Allegheny Energy's first step in
the initial public offering process. Allegheny Energy expects to file a
Registration Statement on Form S-1 in connection with the initial public
offering with the SEC.
TRANSFER AND ACQUISITION OF GENERATING ASSETS AND GENERATING CAPACITY
SINCE FORMATION
TRANSFER OF GENERATING ASSETS IN 1999
At December 31, 1999, we had generating capacity of 2,900 MW. This
included the negotiated transfer by West Penn of 3,778 MW of its deregulated
generating capacity at a net book value of $465.4 million in the fourth quarter
of 1999, the transfer of West Penn's entitlement to 105 MW in the Ohio Valley
Electric Corporation and the purchase of 276 MW of capacity at Fort Martin Unit
No. 1 from AYP Energy, Inc., a subsidiary of Allegheny Energy. The 3,778 MW
transferred included West Penn's ownership interest in Allegheny Generating
Company, or AGC. AGC's only asset is a 40% interest, representing 960 MW, in the
Bath County pumped-storage hydroelectric station and its connecting transmission
facilities. During the period from November 18, 1999, through January 1, 2000,
we leased back to West Penn one-third, or 1,259 MW, of the generating assets it
had transferred to us. The generating capacity of 1,259 MW is not included in
the 2,900 MW at December 31, 1999.
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TRANSFER OF GENERATING ASSETS IN 2000
During 2000, we increased our generating capacity by 3,572 MW to 6,472
MW. The increase in generating capacity included, among other things, the
negotiated transfer by Potomac Edison of approximately 2,100 MW of its Maryland,
Virginia, and West Virginia jurisdictional generating assets at a net book value
of $227.5 million in August 2000 and the transfer of Potomac Edison's
entitlement to 97 MW in the Ohio Valley Electric Corporation. The 2,100 MW
transferred included Potomac Edison's ownership interest in AGC. The increase of
3,572 MW during 2000 also includes 1,259 MW that was released to us as a result
of the expiration of the lease with West Penn on January 1, 2000.
TRANSFER AND ACQUISITION OF GENERATING ASSETS AND GENERATING CAPACITY IN
THE FIRST NINE MONTHS OF 2001
During the first nine months of 2001, we increased our ownership and
contractual right to control generating capacity by 3,324 MW to 9,796 MW. For
the twelve month period ended September 30, 2001, we had increased our ownership
of and contractual right to control generating capacity by 3,440 MW or 54% to
9,796 MW from 6,356 MW owned or under contractual control as of September 30,
2000. The increase in generating capacity in the first nine months of
2001 included:
o in June 2001, the negotiated transfer by Monongahela Power of
approximately 352 MW of its Ohio and FERC jurisdictional
generating assets at a net book value of $48.8 million. The 352 MW
transferred included the Ohio part of Monongahela Power's
ownership interest in AGC;
o in June 2001, the transfer by Allegheny Energy of 83 MW of
generating capacity in the Conemaugh generating station. Allegheny
Energy purchased this capacity from Potomac Electric Power Company
in January 2001 at a cost of approximately $79 million. The 83 MW
represents approximately a 5% ownership interest in the 1,711 MW
Conemaugh generating station located in west-central Pennsylvania;
o in June 2001, the transfer by Allegheny Energy of two 44 MW
simple-cycle natural gas combustion turbines in Springdale,
Pennsylvania by merging its subsidiary, Allegheny Energy Units
No. 1 & 2, LLC, with us;
o in May 2001, the acquisition of three natural gas-fired generating
facilities totaling 1,710 MW of peaking capacity from Enron North
America Corporation. We refer to these assets as the Midwest
Assets. All three facilities had been in service with their former
owner since June 2000. They include the 656 MW Lincoln Energy
Center plant in Manhattan, Illinois, the 508 MW Wheatland plant in
Wheatland, Indiana and the 546 MW Gleason plant in Gleason,
Tennessee. The $1.053 billion purchase price was financed with
short-term debt of $550 million from a group of credit providers,
a $325 million parent loan, a $175 million parent equity
contribution, and other short-term debt;
o in February 2001, the expansion through improvements of
generating capacity of one plant by 91 MW; and
o in March 2001, the acquisition of the contractual right to control
1,000 MW in connection with the acquisition from Merrill Lynch of
the Energy Trading Business described below.
ACQUISITION OF GLOBAL ENERGY MARKETS
In March 2001, we acquired Global Energy Markets, the energy commodity
marketing and trading business of Merrill Lynch Capital Services, Inc. or
Merrill Lynch. We refer to the acquired business as the Energy Trading Business.
This Energy Trading Business helps us optimize our portfolio of generating
assets by significantly enhancing our wholesale marketing, energy trading, fuel
procurement and risk management activities. The Energy Trading Business has also
expanded our expertise in nation-wide trading, fuel procurement, market analysis
and risk management. This business therefore provides us with valuable market
intelligence to help us better identify opportunities to expand our acquisition
and development activities and to compete outside our traditional regions.
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In addition, the Energy Trading Business enables us to provide customized energy
management solutions to wholesale, industrial and commercial customers. The
Energy Trading Business now operates as one of our wholly-owned subsidiaries,
Allegheny Energy Global Markets, LLC. The acquisition of the Energy Trading
Business from Merrill Lynch included a long-term contractual right to control
1,000 MW of generating capacity in Southern California.
See Note 2 to our consolidated financial statements for the period ended
September 30, 2001, for additional information regarding the acquisition of the
Energy Trading Business.
RECENT POWER SALES AGREEMENTS
In March 2001, we entered into a power sales agreement with the
California Department of Water Resources, or CDWR, the electricity buyer for the
state of California. The $4.5 billion contract is for a period through December
2011. We began delivering power under this agreement in late March 2001. Under
this agreement, we have committed to supply the State of California with
contract volumes varying from 150 MW to 500 MW through December 2004. For the
last seven years of the contract, the contract volume will be fixed at 1,000 MW.
We plan to supply this power primarily through our contractual right to 1,000 MW
of generating capacity in California, which we acquired as part of the
acquisition of the Energy Trading Business.
In August 2001, we were the successful bidder to supply Baltimore Gas &
Electric Company with electricity from July 2003 through June 2006. We are
committed to supply Baltimore Gas & Electric Company with an amount needed to
fulfill 10% of its provider-of-last-resort obligations.
We were named the electric generation supplier for eight boroughs in New
Jersey that own and operate electric utilities as departments of municipal
governments. The following eight New Jersey boroughs have signed up with us:
Madison, Butler, Milltown, Seaside Heights, South River, Pemberton, Park Ridge,
and Lavallette. The multi-year contract will begin in June 2002. The contract,
which will supply a total of 150 MW of electricity to the boroughs, will run
through 2004.
ANNOUNCED CONSTRUCTION AND DEVELOPMENT PLANS AND ASSET TRANSFERS
Since January 2000, we have announced construction and development
plans, pending transfers, and contractual rights to control an additional 4,891
MW of generating capacity. This additional capacity will be phased in as it
becomes available.
CONSTRUCTION AND DEVELOPMENT PLANS
Additional generating capacity through announced construction and
development plans includes:
o construction of a 1,080 MW base-load natural gas-fired generating
facility in La Paz County, Arizona, approximately 75 miles west
of Phoenix. We expect construction to begin on the $540 million
combined-cycle facility in 2002 and be completed by 2005;
o construction of a 630 MW intermediate-load and peaking natural
gas-fired facility in St. Joseph County, Indiana. We expect
construction on the facility to begin in 2002 and to be completed
in two stages. Commercial operation of the peaking capacity
consisting of two 44 MW simple-cycle combustion turbines is
expected to begin in 2003, followed by the addition of 542 MW of
combined-cycle, intermediate-load capacity, which is expected to
begin in 2005;
o construction of a 540 MW combined-cycle generating plant in
Springdale, Pennsylvania, at a cost of $318 million. The new
facility will include two natural gas-fired combustion turbines
and a steam turbine. We expect this facility to be operational in
2003;
o a joint venture with CONSOL Energy, Inc. to construct an 88 MW
natural gas-fired generating facility in Buchanan County in
southwest Virginia of which we will own 44 MW of generating
capacity. The facility is expected to be in operation by
mid-2002;
-27-
o construction of two 44 MW simple-cycle gas combustion turbines
near Chambersburg, Pennsylvania, which are currently available
for operation on demand; and
o an additional 48 MW of generating capacity from expansion of
existing plants.
CONTRACTUAL CONTROL OF CAPACITY
In May 2001, we signed a 15-year agreement with Las Vegas Cogeneration
II, L.L.C. This agreement gives us the contractual right to control 222 MW of
generating capacity in a natural gas-fired, combined cycle generating facility,
currently under construction by a third party, in Las Vegas, Nevada, beginning
in the third quarter of 2002. See note 12 to our Consolidated Financial
Statements for the period ended September 30, 2001 regarding this agreement and
estimates of the fair value of this agreement as of September 30, 2001.
In November 2001, we announced that we will participate in a joint
venture with SEF Development LTD. to own and develop a 79 MW barge mounted,
natural gas-fired combustion turbine generating facility to be located in the
Brooklyn Navy Yard, New York. We and SEF Development, will each have a 50%
ownership interest in the joint venture entity. Under the terms of the joint
venture, we will also enter into an agreement with the joint venture entity to
contractually control the entire 79 MW of generating capacity, beginning in mid
2002, when it becomes operational.
ADDITIONAL ASSET TRANSFERS
Additional generating capacity through further asset transfers includes:
o transfer of the remaining 2,111 MW from Monongahela Power once
tax changes related to the deregulation of the retail power
market in West Virginia have been passed by the West Virginia
Legislature or the West Virginia Public Service Commission takes
regulatory action. For a discussion of developments in West
Virginia relating to this transfer, see "-- Developments in West
Virginia relating to the generating asset transfer from
Monongahela Power"; and
o transfer of an additional 49 MW of generating capacity, including
46 MW from the Hunlock Creek generating station near
Wilkes-Barre, Pennsylvania. We have sought approval from the SEC
in the initial public offering U-1 application described above to
transfer this generating capacity. We anticipate that the
transfer will be completed prior to the initial public offering.
POWER SALES AGREEMENTS FOR THE PROVIDER-OF-LAST-RESORT OBLIGATIONS OF ALLEGHENY
ENERGY'S UTILITY SUBSIDIARIES
Under the terms of the deregulation plans approved in Pennsylvania for
West Penn, in Maryland for Potomac Edison, and in Ohio for Monongahela Power,
West Penn, Potomac Edison and Monongahela Power are obligated to provide
electricity during a transition period to all customers who do not choose an
alternate supplier of electricity and to customers that switch back from
alternate suppliers. For West Penn, the Pennsylvania transition period continues
through December 31, 2008 for all customers with escalating capped rates. For
residential customers of Potomac Edison in Maryland, the transition period
continues through December 31, 2008. For commercial and industrial customers of
Potomac Edison in Maryland, the transition period continues through December 31,
2004. For Monongahela Power, the transition period for Ohio residential and
small commercial customers continues through December 31, 2005, and for all
other Ohio customers through December 31, 2003.
Pursuant to long-term power sales agreements, we provide West Penn,
Potomac Edison and Monongahela Power with the amount of electricity, up to their
provider-of-last-resort retail load, that they may demand during the
Pennsylvania, Maryland, and Ohio transition periods. We expect to provide power
pursuant to similar obligations to Potomac Edison and Monongahela Power in West
Virginia as this state implements customer choice. We recently renegotiated a
power sales agreement with Potomac Edison with respect to its Virginia customers
under which we have agreed to provide it with the amount of electricity up to
its provider-of-last-resort retail load that it may demand. The transition
period for customer choice in Virginia is scheduled to begin on January 1, 2002
and runs
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through to July 2007. A significant portion of the normal operating capacity of
our fleet of transferred generating assets is currently required to fulfill our
obligations under these power sales agreements, but we expect that this will
decrease over time. As a result, these power sales agreements will provide us
with a steady revenue stream during the transition periods discussed above.
These agreements do not, however, provide us with any guaranteed level of
customer sales and also mean that we are limited in our ability to pass on to
the regulated utility subsidiaries of Allegheny Energy the risk of fuel price
increases and increased costs of environmental compliance.
Our power sales agreements with West Penn, Monongahela Power with
respect to its Ohio customers and Potomac Edison with respect to its Maryland
and Virginia customers, to provide them with an amount of electricity up to
their provider-of-last-resort retail load, have a fixed price as well as a
market-based pricing component. As the amount of generating capacity we must
deliver under these agreements decreases during the transition periods described
above, the amount of electricity that is subject to market prices escalates each
year. We expect that when the transition periods end, West Penn, Potomac Edison
and Monongahela Power with respect to its Ohio customers will pay us market
rates for the entire amount of electricity provided to them.
We cannot terminate the power sales agreements with West Penn,
Monongahela Power and Potomac Edison unless there is a completed hostile
takeover of Allegheny Energy.
Until customer choicer is implemented in West Virginia and a power
sales agreement is entered into, the assets transferred to us by Potomac Edison
will continue to serve the retail load for West Virginia customers of Potomac
Edison.
DEVELOPMENTS IN WEST VIRGINIA RELATING TO THE GENERATING ASSET TRANSFER FROM
MONONGAHELA POWER
In March 2000, the West Virginia Legislature passed House Resolution 27
approving, with certain modifications, an electric deregulation plan submitted
by the West Virginia Public Service Commission. The plan provides for all
customers to have choice of a generation supplier and allows Monongahela Power
to transfer the West Virginia portion, approximately 2,111 MW, of its generating
assets to us.
Under House Resolution 27, the West Virginia deregulation plan cannot
occur until the West Virginia Legislature enacts certain tax changes regarding
the preservation of tax revenues for state and local governments. The 2001
legislative session ended on April 14, 2001, without enactment of the necessary
tax changes that would allow implementation of the deregulation plan to occur in
West Virginia. Final legislative activity regarding implementation of the
deregulation plan has been postponed for a year. Efforts are underway to develop
a consumer education program to communicate to targeted audiences the merits of
restructuring. We anticipate that legislative action to implement the West
Virginia plan will be sought in 2002. As a result, Monongahela Power has to date
not been able to transfer its West Virginia generating assets to us.
We are exploring other ways to complete the transfer to us of
Monongahela Power's West Virginia generating assets. The June 2000 order by the
West Virginia Public Service Commission permits Monongahela Power to submit a
petition to the West Virginia Public Service Commission seeking approval to
transfer its West Virginia generating assets prior to the implementation of the
deregulation plan. In August 2000, with a supplemental filing in October 2000,
Monongahela Power filed a petition seeking West Virginia Public Service
Commission approval of that transfer. The West Virginia Public Service
Commission has not yet acted on the request. After reaching a settlement with
the West Virginia Public Service Commission or receiving authorization from the
West Virginia Legislature and the SEC releasing jurisdiction over the West
Virginia generating assets, Monongahela Power intends to transfer the generating
assets to us as soon as possible.
UTILITY WORKERS UNION OF AMERICA CONTRACT NEGOTIATIONS
On April 30, 2001, our collective bargaining agreement with the Utility
Workers Union of America Local 102, or UWUA, expired. The parties entered into a
contract extension through May 31, 2001. We were unable to reach agreement with
the UWUA on a new labor pact by this deadline. Under a federal mediator's
suggestion, the parties continue to work under the terms and conditions of the
prior labor agreement on a day-to-day basis. A
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seven-day strike notice remains in effect for the UWUA Local 102 should it
decide to engage in any job action. The agreement covers approximately 290 of
Allegheny Energy's employees that directly support our operations.
CLAIM BY THE UWUA TO USE THE PROCEEDS OF THE INITIAL PUBLIC OFFERING TO OFFSET
RECOVERY FROM WEST PENN CUSTOMERS OF STRANDED GENERATING COSTS
In September 2001, the UWUA filed a petition with the Pennsylvania
Public Utility Commission. The UWUA has requested that the Pennsylvania Public
Utility Commission determine that the initial public offering of common stock of
our proposed new parent holding company and the subsequent distribution of
shares of common stock of that holding company to Allegheny Energy stockholders
be treated under the Pennsylvania deregulation settlement order as a "sale" of
the generating assets previously transferred to us by West Penn. If the UWUA is
successful in its claim and the initial public offering and distribution
constitute a sale, we will be required to use the proceeds of the initial public
offering to offset and reduce the $670 million in stranded generating costs that
West Penn is entitled to recover from its Pennsylvania customers as a surcharge.
The UWUA contends that the initial public offering should be used to value the
generating assets transferred from West Penn and that this amount be returned to
West Penn. Although we do not believe that the UWUA petition has merit, we
cannot predict the outcome of the Pennsylvania Public Utility Commission
determination or, if the UWUA is successful in its claim, its effect on the
initial public offering and distribution.
NEW ACCOUNTING STANDARDS
In July 2001, the Financial Accounting Standards Board, or FASB, issued
Statement of Financial Accounting Standards, or SFAS, No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." These
standards significantly change the accounting for business combinations and
goodwill in two significant ways. SFAS No. 141 requires that the purchase method
of accounting be used for all business combinations initiated after June 30,
2001. Use of the pooling-of-interests method will be prohibited. We do not
expect SFAS No. 141 to have a material effect on us.
SFAS No. 142 changes the accounting for goodwill from an amortization
method to an impairment-only approach. Amortization of goodwill, including
goodwill recorded in past business combinations, will cease upon adoption of the
standard, which for us will be January 1, 2002. Subsequently, we will test our
goodwill annually for impairment. Intangible assets other than goodwill will
continue to be amortized over their useful lives and reviewed for impairment in
accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of." As of September 30, 2001,
we had $374 million of goodwill. We estimate goodwill amortization in 2001 to be
$20.1 million ($25.4 million on an annualized basis). We will be evaluating the
effect of adopting SFAS No. 142 on our results of operations and financial
position prior to our adoption of the standard on January 1, 2002.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This standard requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred with a corresponding increase in the carrying amount of the
related long-lived asset. Over time, the liability will be accreted to its
present value each period, and the capitalized cost will be depreciated over the
useful life of the asset. Upon settlement of the liability, an entity either
will settle the obligation for its recorded amount or incur a gain or loss upon
settlement. We will be evaluating the effect of adopting SFAS No. 143 on our
results of operations and financial position prior to our adoption of the
standard on January 1, 2003.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This standard, which we will adopt
on January 1, 2002, establishes one accounting model for long-lived assets to be
disposed of by sale, including discontinued operations, and carries forward the
general impairment provisions of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 144 is
not expected to have a material effect on us.
-30-
REVIEW OF OPERATIONS FOR THE FIRST NINE MONTHS OF 2001
EARNINGS SUMMARY
Because of the high levels of acquisition and transfer activity
described above since our formation, it may be difficult for investors to
evaluate the probable impact of these acquisitions and generating asset
transfers on our financial performance or make meaningful comparisons between
reporting periods until we have operating results for a number of reporting
periods from these facilities and assets. It may, therefore, not be possible to
draw meaningful comparisons and conclusions from the year-to-year, nine
month-to-nine month and three month-to-three month comparisons discussed in
"--REVIEW OF OPERATIONS FOR THE 2000 AND 1999 PERIODS", "--REVIEW OF OPERATIONS
FOR THE FIRST NINE MONTHS OF 2001" and "--FINANCIAL CONDITION, REQUIREMENTS AND
RESOURCES", because of the significant impact on our financial statements of
added generating capacity, especially the acquisition of the Midwest Assets in
the second quarter of 2001, the acquisition of the Energy Trading Business in
the first quarter of 2001, and the transfer of generating assets from Potomac
Edison in the third quarter of 2000. For the twelve month period ended September
30, 2001, we increased our ownership of and contractual right to control
generating capacity to 9,796 MW from 6,356 MW owned or under contractual control
as of September 30, 2000. Similarly, for the twelve month period ended June 30,
2001, we had increased our ownership of and contractual right to control
generating capacity to 9,796 MW from 4,159 MW owned or under contractual control
as of June 30, 2000.
Consolidated net income for the third quarter and first nine months of
2001 and 2000 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------ ------------------
2001 2000 2001 2000
---- ---- ---- ----
(THOUSANDS OF DOLLARS)
Consolidated Income Before Income
Taxes, Minority Interest, and
Cumulative Effect of Accounting
Change $184,481 $23,042 $363,901 $ 62,717
Federal and State Income Taxes 65,872 7,150 129,044 18,721
Minority Interest 962 1,133 3,646 1,133
-------- ------- -------- ---------
Consolidated Income Before
Cumulative Effect of Accounting
Change 117,647 14,759 231,211 42,863
Cumulative Effect of Accounting
Change (31,147)
-------- ------- -------- ---------
Consolidated Net Income $117,647 $14,759 $200,064 $ 42,863
======== ======= ======== =========
The increase in consolidated net income for the third quarter and first
nine months of 2001 as compared to the same periods in 2000 reflects the growth
in generating capacity through transfers from the regulated utility subsidiaries
and other subsidiaries of Allegheny Energy, acquisition and construction of
additional generating assets, and the results of the energy trading activities
of Allegheny Energy Global Markets.
On March 16, 2001, we acquired the Energy Trading Business. This
acquisition helps us optimize our portfolio of generating assets by
significantly enhancing our wholesale marketing, energy trading, fuel
procurement and risk management activities. We consider this business to be an
integral part of our energy supply business and key to our strategy of becoming
a national energy merchant. Allegheny Energy Global Markets markets and trades
electricity, natural gas, oil and other energy commodities using primarily
over-the-counter contracts and exchange-traded contracts, such as those traded
on the New York Mercantile Exchange, or NYMEX. The unrealized and realized gains
from energy trading activities are discussed below under "--OPERATING REVENUES
- -- WHOLESALE." See Note 2 to our consolidated financial statements for the
period ended September 30, 2001, for additional information regarding the
acquisition of the Energy Trading Business.
We have certain option contracts that meet the derivative criteria in
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
which did not qualify for hedge accounting. In accordance with
-31-
SFAS No. 133, we recorded a charge of $31.1 million against earnings net of the
related tax effect ($52.3 million before tax) for these contracts as a change in
accounting principle on January 1, 2001. See Note 10 to our consolidated
financial statements for the period ended September 30, 2001, for additional
details.
OPERATING REVENUES
Total operating revenues for the third quarter and first nine months of
2001 and 2000 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
-------------- -----------------
2001 2000 2001 2000
---- ---- ---- ----
(THOUSANDS OF DOLLARS)
Operating revenues:
Retail $ 26,406 $ 42,843 $ 113,238 $ 155,828
Wholesale 2,999,393 407,602 6,114,380 822,171
Affiliated 286,407 238,785 845,362 497,601
------------ --------- ------------ -----------
Total operating revenues $ 3,312,206 $ 689,230 $ 7,072,980 $ 1,475,600
============ ========= =========== ===========
RETAIL. We continue to be active in the retail markets as an alternative
generation supplier in states where retail competition has been implemented. The
number of retail customers declined from 170,000 as of December 31, 2000, to
approximately 160,000 at September 30, 2001. The reduction in retail revenues
for the third quarter and first nine months of 2001 was primarily due to our
shift in focus away from retail customers towards the wholesale power markets
and energy commodity trading.
WHOLESALE. The increase in wholesale revenues for the third quarter and
first nine months of 2001 was primarily due to the results of energy trading
activities of Allegheny Energy Global Markets. We record contracts entered into
in connection with energy trading at fair value on the consolidated balance
sheet, with all changes in fair value recorded as gains and losses on the
consolidated statement of operations. Net unrealized gains, before tax, of
$387.1 million and $567.6 million were recorded to the consolidated statement of
operations in wholesale revenues to reflect the change in fair value of the
energy commodity contracts for the third quarter and first nine months of 2001,
respectively. The realized revenues from energy trading activities, with the
exception of some financial derivative instruments, including swaps and certain
options, are recorded on a gross basis as individual discrete transactions as
either revenues or expenses because the contracts require physical delivery of
the underlying asset. The six month period ended September 30, 2001 included
realized losses from energy trading activities of $122.9 million. See Note 6 to
our consolidated financial statements for the period ended September 30, 2001,
for additional details.
The increase in wholesale revenues also reflects increased transactions
in the unregulated marketplace to sell electricity to wholesale customers and is
also due to having increased generation available for sale. Potomac Edison
transferred 2,100 MW of its generating assets to us in August 2000. In June
2001, Monongahela Power transferred 352 MW of its Ohio and FERC jurisdictional
generating assets to us. On May 3, 2001, we also completed the acquisition of
three natural gas-fired power plants with a total generating capacity of 1,710
MW in Illinois, Indiana and Tennessee. As a result, we had more generation
available for sale into the deregulated marketplace in the third quarter and
first nine months of 2001 and had concluded more commitments to sell generation
in that marketplace.
AFFILIATED. Affiliated revenues are revenues that we obtained from
Allegheny Energy's utility subsidiaries under power sales agreements and a
generating asset lease. In Maryland, Ohio, Pennsylvania and Virginia, we are
obligated under power sales agreements to supply the regulated utility
subsidiaries of Allegheny Energy - West Penn, Monongahela Power and Potomac
Edison - with power through various periods up to 2008. Under these agreements,
we are obligated to provide these companies with the amount of electricity, up
to their provider-of-last-resort retail load, that they may demand. We expect to
provide power pursuant to similar obligations to Potomac Edison and Monongahela
Power in West Virginia when this state implements customer choice.
The transfer of Potomac Edison's generating assets to us on August 1,
2000, included Potomac Edison's generating assets located in West Virginia. A
portion of these generating assets have been leased back to Potomac
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Edison to serve its West Virginia jurisdictional retail customers. Affiliated
revenue in 2001 includes $57.5 million for this rental income. The original
lease term was for one year. The parties have mutually agreed to continue the
lease beyond August 1, 2001.
COST OF SALES
FUEL EXPENSES. Fuel expenses increased $39.1 million for the third
quarter and $122.4 million for the first nine months of 2001. Fuel expenses
represent the cost of fuel consumed by our generating stations and the results
of the energy commodity contracts used to manage the price risk associated with
the purchase of natural gas for use in certain generating stations. During 2000
approximately 88%, and during the first nine months of 2001 approximately 90%,
of our fuel requirements was purchased under long-term arrangements with terms
of greater than 12 months. We depend on short-term arrangements and spot
purchases for our remaining requirements. Until 2005, we expect to satisfy our
total coal requirements with coal acquired under existing contracts or from
current suppliers. For the six month period ended September 30, 2001 we recorded
a realized gain of $15.6 million and an unrealized gain of $25.1 million on our
fuel management activities. We are limited in our ability to pass on to
customers the risk of fuel price increases and increased costs of environmental
compliance under our power sales agreements with the regulated utility
subsidiaries of Allegheny Energy.
The increase in fuel expenses for the third quarter and first nine
months of 2001 was primarily associated with the transfer of 2,100 MW of Potomac
Edison's generating assets to us in August 2000. The increase in fuel expenses
for the first nine months of 2001 also reflected the transfer to us in June 2001
of 352 MW of Monongahela Power's Ohio and FERC jurisdictional generating assets
and the purchase on May 3, 2001 of the Midwest Assets.
PURCHASED ENERGY AND TRANSMISSION. Purchased energy and transmission
increased $2.3 billion for the third quarter and $4.9 billion for the first nine
months of 2001. The increases were primarily related to the wholesale power
marketing and energy commodity trading activities of Allegheny Energy Global
Markets and power purchased to fulfill our power sales agreement obligations to
West Penn, Potomac Edison and Monongahela Power.
OTHER OPERATING EXPENSES
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES. Selling, general and
administrative expenses increased by $41.2 million for the third quarter and $76
million for the first nine months of 2001. The increase in selling, general, and
administrative expenses was primarily due to salary and benefit expenses related
to Allegheny Energy Global Markets, financing expenses related to the issuance
of short-term debt, and rent expense for Allegheny Energy Global Markets' office
in New York City and our corporate office in Monroeville, Pennsylvania. See Note
11 to our consolidated financial statements for the period ended September 30,
2001, for additional information regarding selling, general, and administrative
expenses.
OTHER OPERATION EXPENSES. Other operation expenses increased $4.1
million for the third quarter and $20.7 million for the first nine months of
2001. Other operation expenses primarily include power station operating costs
and other operating costs. The increases in the other operation expenses for the
third quarter and first nine months of 2001 were primarily due to the operation
of 2,100 MW of generating assets transferred to us by Potomac Edison in August
2000, the operation of 1,710 MW of the Midwest Assets, and, to a lesser extent,
the operation of 352 MW of Monongahela Power's Ohio and FERC jurisdictional
generating assets transferred to us in June 2001.
MAINTENANCE EXPENSES. Maintenance expenses increased by $10.8 million
for the third quarter and $44.7 million for the first nine months of 2001.
Maintenance expenses represent costs incurred to maintain the power stations and
general plant and reflect routine maintenance of equipment as well as planned
repairs and unplanned expenditures primarily from forced outages at the power
stations. Variations in maintenance expense result primarily from unplanned
events and planned projects, which vary in timing and magnitude depending upon
the length of time equipment has been in service without an overhaul and the
amount of work found necessary when the equipment is inspected.
-33-
Our increase in maintenance expenses was primarily due to increased
power station maintenance expenses related to the assets transferred to us by
Allegheny Energy's regulated utility subsidiaries and scheduled maintenance at
the Fort Martin, Armstrong, Harrison, Hatfield, Pleasants and combustion turbine
power stations.
DEPRECIATION AND AMORTIZATION EXPENSES. Depreciation and amortization
expenses increased by $20.1 million for the third quarter and $41.4 million for
the first nine months of 2001. The increase was primarily due to depreciation
expense related to the Midwest Assets, amortization of goodwill related to the
acquisition of the Energy Trading Business, and depreciation expense related to
generating assets that were transferred to us by Allegheny Energy's regulated
utility subsidiaries.
TAXES OTHER THAN INCOME TAXES. Taxes, other than income taxes, increased
by $0.4 million for the third quarter and $9.3 million for the first nine months
of 2001. Taxes, other than income taxes, consist primarily of gross receipts,
taxes on revenues from retail customers, property taxes, and West Virginia
business and occupation taxes. The increase in taxes other than income taxes for
the third quarter and first nine months of 2001 reflects the transfer of 2,100
MW of Potomac Edison's generating assets in August 2000 and, to a lesser extent,
the transfer to us of 352 MW of Monongahela Power's Ohio and FERC jurisdictional
generating assets in June 2001.
OTHER INCOME AND EXPENSES
Other income and expenses decreased by $0.4 million for the third
quarter of 2001 and increased by $1.6 million for the first nine months of 2001.
Other income and expenses primarily represented our share of equity in earnings
of AGC through July 2000. The first nine months of 2001 included a gain on
disposal of property of $3.5 million; and the first nine months of 2000 included
a loss on disposal of property of $2.7 million.
INTEREST CHARGES
Interest on long-term debt and other interest for the third quarter and
first nine months of 2001 and 2000 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------- --------------------
2001 2000 2001 2000
---- ---- ---- ----
(THOUSANDS OF DOLLARS)
Interest on long-term debt $16,115 $ 8,932 $42,073 $19,828
Other interest 18,886 2,762 36,520 4,441
Interest capitalized (2,094) (1,508) (4,545) (3,861)
------- -------- -------- --------
Total interest charges $32,907 $10,186 $74,048 $20,408
======= ======= ======= =======
The increase in interest on long-term debt of $7.2 million in the third
quarter and $22.2 million in the first nine months of 2001 resulted from
increased average long-term debt outstanding.
The increase in average long-term debt outstanding resulted from debt
issued for the acquisition of the Energy Trading Business and debt assumed by us
as a result of generating asset transfers from Allegheny Energy's regulated
utility subsidiaries.
In June 2001, we assumed approximately $15.9 million of long-term debt
as a result of the transfer to us of 352 MW of Monongahela Power's Ohio and FERC
jurisdictional generating assets. In March 2001, we issued $400 million of
unsecured 7.80% notes due 2011 to pay for a portion of the cost of the Energy
Trading Business.
The interest on long-term debt also reflects interest on $230.8 million
and $184.2 million of pollution control debt associated with the November 1999
transfer of West Penn's generating assets and the August 2000 transfer of 2,100
MW of Potomac Edison's generating assets. We also assumed debt in the form of a
$130 million bank loan in connection with the purchase of 276 MW of unregulated
generating capacity from an Allegheny Energy unregulated subsidiary which was
refinanced with short-term debt in October 2000. For additional information
regarding our short-term and long-term debt, see "--FINANCIAL CONDITION,
REQUIREMENTS AND RESOURCES -- FINANCING."
-34-
Other interest expense represents interest expense for loans from
Allegheny Energy and borrowings from banks and commercial paper. Other interest
expense increased by $16.1 million in the third quarter and $32.1 million for
the first nine months of 2001. The increases resulted from increased average
short-term debt. Capitalized interest costs are related to interest on capital
expenditures and were recorded in accordance with SFAS No. 34, "Capitalization
of Interest Cost."
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased by $58.7 million for the third
quarter and increased by $110.3 million for the first nine months of 2001 due to
increased taxable income.
MINORITY INTEREST
Minority interest decreased by $0.2 million for the third quarter and
increased by $2.5 million for the first nine months of 2001. As of September 30,
2001, the minority interest represents Monongahela Power's 22.97% minority
interest in AGC. In August 2000, Potomac Edison transferred to us all of its
generating assets, except certain hydroelectric facilities located in Virginia
at net book value. The asset transfer included Potomac Edison's 28% ownership of
AGC. As a result of the transfer, our ownership increased from 45% as of July
31, 2000, to 73% as of August 1, 2000. Effective August 1, 2000, our
consolidated financial statements include the operations of AGC and the related
minority interest. In connection with the transfer of 352 MW of Monongahela
Power's generating assets, we received an additional 4.03% ownership of AGC,
which increased our ownership percentage to its current level of 77.03%.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
We have certain option contracts that meet the derivative criteria in
SFAS No. 133, which did not qualify for hedge accounting. In accordance with
SFAS No. 133, we recorded a charge of $31.1 million against earnings, net of the
related tax effect ($52.3 million before tax), for these contracts as a change
in accounting principle on January 1, 2001. See Note 10 to our consolidated
financial statements for the period ended September 30, 2001, for additional
information.
OTHER COMPREHENSIVE INCOME
Other comprehensive income includes an unrealized loss, net of
reclassification to earnings and tax, on cash flow hedges of $1.5 million for
the first nine months of 2001. During the third quarter of 2001, we reclassified
$3.1 million, net of tax, from other comprehensive income to earnings related to
losses associated with cash flow hedges.
REVIEW OF OPERATIONS FOR THE 2000 AND 1999 PERIODS
EARNINGS SUMMARY FOR THE 2000 AND 1999 PERIODS
We refer to the period from our inception on November 18, 1999, to
December 31, 1999, as the 1999 period.
Consolidated net income for the year ended December 31, 2000, and for
the 1999 period was as follows:
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FROM
NOVEMBER 18, 1999
YEAR ENDED INCEPTION DATE TO
DECEMBER 31, 2000 DECEMBER 31, 1999
----------------- -----------------
(THOUSANDS OF DOLLARS)
Consolidated Income Before Income Taxes and Minority
Interest $114,077 $12,036
Federal and State Income Taxes 36,081 2,504
Minority Interest 2,508
-------- -------
Consolidated Net Income $ 75,488 $ 9,532
======== =======
For the year ended December 31, 2000, earnings reflect the growth in our
business, which in part, was due to the availability of the final one-third of
West Penn's generating assets and the August 2000 transfer to us of 2,100 MW of
Potomac Edison's generating assets. Consolidated net income for the 1999 period
represented earnings on the two-thirds of West Penn generating assets that were
available to us on November 18, 1999, generating assets purchased by us in
December 1999 from another affiliate, and other marketing activities.
OPERATING REVENUES
Total operating revenues for the year ended December 31, 2000, and for
the 1999 period were as follows:
FROM
NOVEMBER 18, 1999
YEAR ENDED INCEPTION DATE TO
DECEMBER 31, 2000 DECEMBER 31, 1999
----------------- -----------------
(THOUSANDS OF DOLLARS)
Operating revenues:
Retail $ 197,189 $ 21,283
Wholesale 1,285,102 73,259
Affiliated 777,281 46,332
---------- --------
Total operating revenues $2,259,572 $140,874
========== ========
RETAIL. We continued to enter into retail markets as an alternative
generation supplier in states where retail competition had been implemented. In
2000, we had approximately 170,000 retail customers in Pennsylvania, New Jersey,
Ohio, Maryland, and Delaware.
WHOLESALE. As a result of the Electricity Generation Customer Choice and
Competition Act in Pennsylvania, two-thirds of West Penn's generation was
available in November 1999 and the final one-third was available in the first
quarter of 2000 for sale into the deregulated marketplace, subject to our
obligations under a power sales agreement for West Penn's
provider-of-last-resort retail load obligations. In addition, on August 1, 2000,
Potomac Edison transferred to us its 2,100 MW of generating assets. As a result,
we had more generation available for sale in 2000 into the deregulated wholesale
marketplace. We also engaged in increased buy-sell transactions to optimize the
value of our generating assets in the unregulated marketplace and to take
advantage of arbitrage opportunities between adjacent markets. Wholesale
revenues in 2000 also include an $8.4 million net unrealized gain to reflect the
fair value of our energy trading contracts.
AFFILIATED. In Maryland and Pennsylvania, we entered into long-term
power sales agreements to supply West Penn and Potomac Edison with power through
various periods up to 2008. Under these agreements, we are obligated to provide
these regulated utility subsidiaries with the amount of electricity, up to their
provider-of-last-resort retail load, that they may demand.
The transfer of Potomac Edison's generating assets to us in August 2000,
included Potomac Edison's assets located in West Virginia. A portion of these
assets has been leased back to Potomac Edison to serve its West Virginia retail
customers. Affiliated revenue in 2000 includes $37.1 million for this rental
income.
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COST OF SALES
FUEL EXPENSES. Fuel expenses were $317.2 million for the year ended
December 31, 2000 and $18.1 million for the 1999 period. Fuel expenses represent
the cost of fuel consumed by our generating stations. During 2000, we purchased
approximately 88% of our fuel requirements under long-term arrangements with
terms of greater than 12 months. We depended on short-term arrangements and spot
purchases for our remaining requirements. As of December 31, 2000, we owned
generating assets with total capacity of 6,472 MW of which 86% was coal-fired,
10% was pumped-storage and hydroelectric, and 4% was oil and gas-fired.
PURCHASED ENERGY AND TRANSMISSION. Purchased energy and transmission
costs were $1.5 billion for the year ended December 31, 2000 and $84.4 million
for the 1999 period. Purchased energy and transmission costs increased in 2000
primarily due to increased buy-sell transactions in the fourth quarter of 2000,
power purchased to fulfill our power sales agreement obligations to West Penn
and Potomac Edison and unplanned first quarter generating plant outages which
caused us to make purchases of higher-priced power on the open energy market.
The increases in purchased energy and transmission costs for 2000 were also due
to increased purchasing of transmission of electricity for delivery of energy to
customers.
OTHER OPERATING EXPENSES
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES. Selling, general and
administrative expenses were $49.1 million for the year ended December 31, 2000
and $5.3 million for the 1999 period. The increase in selling, general and
administrative expenses is primarily due to an increase in the number of
Allegheny Energy employees supporting our operations. All Allegheny Energy
employees were employed by Allegheny Energy Services Corporation, which performs
services at cost for us in accordance with the Public Utility Holding Company
Act of 1935. We are responsible for our proportionate share of services provided
by Allegheny Energy Services Corporation. See Note J to the consolidated
financial statements for the period ended December 31, 2000, for additional
details.
OTHER OPERATION EXPENSES. Other operation expenses were $32.2 million
for the year ended December 31, 2000 and $2.3 million for the 1999 period. Other
operation expenses primarily include power station operating costs and other
operating costs. The increases in the other operation expenses for 2000 were
primarily due to increased expenses related to the operation of generating
assets transferred during the year 2000.
MAINTENANCE EXPENSES. Maintenance expenses were $80.8 million for the
year ended December 31, 2000 and $4.3 million for the 1999 period. Maintenance
expenses represent costs incurred to maintain the power stations and general
plant and reflect routine maintenance of equipment as well as planned repairs
and unplanned expenditures primarily from forced outages at the power stations.
Variations in maintenance expense result primarily from unplanned events and
planned projects, which vary in timing and magnitude depending upon the length
of time equipment has been in service without an overhaul and the amount of work
found necessary when the equipment is inspected.
DEPRECIATION AND AMORTIZATION EXPENSES. Depreciation and amortization
expenses were $55.3 million for the year ended December 31, 2000 and $8.0
million for the 1999 period. Our depreciation and amortization expenses for 2000
reflect the transfer of West Penn's generating assets and the August 2000,
transfer of 2,100 MW of Potomac Edison's generating assets. AGC's depreciation
expenses of $7.1 million are also included in 2000 for the period August 1
through December 31, 2000 when AGC was a majority-owned consolidated subsidiary.
TAXES OTHER THAN INCOME TAXES. Taxes, other than income taxes, were
$58.5 million for the year ended December 31, 2000 and $5.5 million for the 1999
period. Total taxes, other than income taxes, consist primarily of gross
receipts, taxes on revenues from retail customers, property taxes and West
Virginia business and occupation taxes. The level of taxes, other than income
taxes, for the year 2000 reflects the transfer of the remaining one-third of
generating assets of West Penn and the August 1, 2000 transfer of Potomac
Edison's generating assets.
-37-
OTHER INCOME AND EXPENSES
Other income and expenses was $3.5 million for the year ended December
31, 2000, and $1.2 million for the 1999 period. Other income and expenses
primarily represents our shares of the equity in earnings of AGC through July
2000.
INTEREST CHARGES
Interest on long-term debt and other interest for the year ended
December 31, 2000, and for the 1999 period were as follows:
FROM
NOVEMBER 18, 1999
YEAR ENDED DECEMBER 31, INCEPTION DATE TO
2000 DECEMBER 31, 1999
----------------------- -----------------
(THOUSANDS OF DOLLARS)
Interest on long-term debt...................................... $29,221 $2,135
Other interest.................................................. 8,574 170
Interest capitalized............................................ (4,337) (212)
-------- --------
Total interest charges.......................................... $33,458 $2,093
======= ======
The interest on long-term debt for 2000 reflects interest on $230.8
million and $184.2 million of pollution control debt associated with the
November 1999 transfer of West Penn and August 2000 transfer of Potomac Edison
generating assets, respectively. We also assumed debt in the form of a $130
million bank loan in connection with the purchase of 276 MW of unregulated
generating capacity from an Allegheny Energy unregulated subsidiary which was
refinanced with short-term debt in October 2000. The weighted average interest
rate on long-term debt at December 31, 2000 was 6.1%. For additional information
regarding our short-term and long-term debt, see "--FINANCIAL CONDITION,
REQUIREMENTS AND RESOURCES - FINANCING."
Other interest expense represents interest expense for loans from
Allegheny Energy and borrowings from banks and commercial paper. Capitalized
interest costs are related to interest on capital expenditures and were recorded
in accordance with SFAS No. 34, "Capitalization of Interest Cost."
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes were $36.1 million for the year ended
December 31, 2000, and $2.5 million for the 1999 period.
MINORITY INTEREST
Minority interest was $2.5 million for the year ended December 31, 2000,
and nil for the 1999 period. The minority interest for the year ended December
31, 2000, represents Monongahela Power's 27% minority interest in AGC. In August
2000, Potomac Edison transferred all of its generating assets, except certain
hydroelectric facilities located in Virginia, to us at net book value. The asset
transfer included Potomac Edison's 28% ownership of AGC. As a result of the
transfer, our ownership increased from 45% as of July 31, 2000, to 73% as of
August 1, 2000. Effective August 1, 2000, our consolidated financial statements
include the operations of AGC and the related minority interest.
FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES
LIQUIDITY AND CAPITAL REQUIREMENTS
To meet cash needs for operating expenses, the payment of interest,
retirement of debt, and for our acquisition and construction programs, we have
used internally generated funds, member contributions from Allegheny Energy and
external financings, such as debt instruments, installment loans and lease
arrangements. The
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timing and amount of external financings depend primarily upon economic and
financial market conditions, our cash needs and our capital structure
objectives. The availability and cost of external financings depend upon our
financial condition and market conditions.
We anticipate meeting our 2002 cash needs through internal cash
generation, cash on hand, short-term borrowings as necessary, external
financings, lease arrangements, and by issuing other debt and equity.
Our construction expenditures were $132.6 million for the first nine
months of 2001 and $125.3 million for the first nine months of 2000. Our
construction expenditures were $177.1 million for 2000 and $50.8 million for
1999. As described under "SIGNIFICANT CONTINUING ISSUES - ENVIRONMENTAL ISSUES"
below, we could potentially face significant mandated increases in capital
expenditures and operating costs related to environmental issues. Estimated
construction expenditures include $111 million in 2001 and $109.7 million in
2002 for environmental control technology. Future construction expenditures will
reflect additions of generating capacity to sell into deregulated markets. We
also have additional capital requirements due to an increase in long-term debt.
We estimate our capital expenditures other than construction expenditures to be
$1.7 billion for 2001. This includes the $1.053 billion purchase price for the
Midwest Assets and the purchase price for our acquisition of the Energy Trading
Business.
We estimate our current capital expenditures, excluding capital
expenditures for environmental control technology, and debt maturities for the
remaining three months of 2001 to be approximately $77 million and for 2002 to
be approximately $339 million. These estimates for the remaining three months of
2001 and for 2002 do not include capital expenditures and debt maturities with
respect to Monongahela Power's West Virginia jurisdictional generating assets.
We expect that there will be additional capital expenditures, including
expenditures for environmental control technology, and debt when these
generating assets are transferred to us.
CASH FLOW
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was a use of $125.9 million for the first nine months of
2001 compared to a source of $0.1 million for the first nine months of 2000.
Cash flows used in operations in the first nine months of 2001 increased
by $164.3 million compared to the cash flows used in operations in the first
nine months of 2000, reflecting unrealized gains of $567.6 million on commodity
contracts, net, offset significantly by a $221.9 million net increase in
deferred taxes and a $50.8 million net increase in deposits less customer
deposits due to collateral posted with counterparties and $105.3 million net
increase in prepayments.
Our cash flows used in operations includes the results of energy trading
activities of our Energy Trading Business acquired from Merrill Lynch in March
2001. For the six month period ended September 30, 2001, the energy trading
activities have resulted in approximately $122.9 million of cash outflows. The
cash outflows are mainly related to our contracts and related hedges in the
Western Systems Coordinating Council power market, including the fixed-price
power sales agreement with the California Department of Water Resources and the
contractual control of 1,000 MW of generating capacity in Southern California.
We expect to continue to incur cash outflows related to the Western Systems
Coordinating Council contracts and hedges through 2002. After 2002, we expect to
realize cash inflows related to these long-term contracts for the remaining term
of the contracts, which currently results in significant positive fair value for
the Western Systems Coordinating Council portfolio of contracts.
Cash flows used in investing increased by $1.6 billion for the first
nine months of 2001 compared to the cash flows used in investing for the first
nine months of 2000. In the first nine months of 2001, we paid $489.2 million
for the acquisition of the Energy Trading Business and $1.053 billion for the
acquisition of the Midwest Assets. Construction expenditures during the first
nine months of 2001 were $132.6 million compared to $125.3 million during the
first nine months of 2000.
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Cash flows provided by financing increased by $1.7 billion for the first
nine months of 2001 compared to the cash flows provided by financing for the
first nine months of 2000 period, due primarily to $396.6 million net proceeds
from the issuance of long-term debt for the acquisition of the Energy Trading
Business; $250.6 million increase in equity contributions from Allegheny Energy
primarily for the purchase of the Midwest Assets; $315.7 million increase in
notes payable to Allegheny Energy and affiliates primarily for the purchase of
the Midwest Assets; and a $733.3 million increase in short-term debt for the
purchase of the Energy Trading Business, Allegheny Energy Global Markets'
activities, and other various uses.
Internal generation of cash, consisting of cash flows from operations
reduced by dividends to parent, was $127 million in 2000, compared to a use of
$7 million in the 1999 period. The 1999 negative internal cash flow resulted
primarily from the timing of payments and receipts for accounts receivable and
payable since inception.
Cash flows from operations for 2000 increased by $197.6 million compared
to the 1999 period reflecting a $45.6 million increase in accounts receivable,
net less accounts payable, a $20.9 million increase in affiliated accounts
receivable/payable, net, and a $66.0 million increase in consolidated net
income.
Cash flows used in investing for 2000 increased by $126.6 million
compared to the 1999 period reflecting a $126.4 million increase in construction
expenditures.
Cash flows used in financing for 2000 increased by $47.7 million
compared to the 1999 period reflecting the retirement of long-term debt of
$130.0 million and an increase in payment of dividends to Allegheny Energy of
$63.6 million.
FINANCING
Short-term debt and notes payable to Allegheny Energy and affiliates
increased by $1.1 billion during the first nine months of 2001. As of September
30, 2001, short-term debt and notes payable to Allegheny and affiliates
consisted of commercial paper borrowings of $226.3 million, lines of credit of
$137.2 million, the $550 million bridge loan used to purchase the Midwest Assets
on May 3, 2001, and notes payable to Allegheny Energy and our affiliates of
$452.6 million at rates comparable to short-term rates. We intend to refinance a
significant portion of these obligations with long-term financing within the
next 12 months.
At September 30, 2001, $137.2 million of the $530 million line of credit
with banks remained used and unavailable for future use. The remainder of the
unused lines of credit of $392.8 million, were committed to support outstanding
commercial paper.
Short-term debt and notes payable to Allegheny Energy and affiliates
increased by $198 million in 2000 and consisted of commercial paper borrowings
of $166 million and notes payable to Allegheny Energy and our affiliates of $32
million at rates comparable to short-term rates. At December 31, 2000, unused
lines of credit with banks were $180 million.
Our total long-term debt was $976.2 million as of September 30, 2001,
$563.4 million as of December 31, 2000, and $356.2 million as of December 31,
1999. Our senior unsecured long-term debt of $550 million has been rated "Baa1"
by Moody's and "BBB+" by Standard & Poor's and Fitch. A Baa1 rating by Moody's
falls within the fourth highest of nine major Moody's rating categories. A BBB+
rating by Standard & Poor's falls within the fourth highest of ten major
Standard & Poor's rating categories. A BBB+ rating by Fitch falls within the
fourth highest of eight major Fitch rating categories. These ratings are not a
recommendation to buy, sell or hold this debt and may be suspended, reduced or
withdrawn at any time by the rating agencies if our financial condition and
results of operations change. Each rating should also be evaluated independently
of any other rating. It is our objective to maintain an investment grade rating
after the proposed initial public offering and distribution of shares of common
stock to Allegheny Energy stockholders. Our senior unsecured debt consists of
the $400 million of 7.80% notes due 2011 issued in connection with the
acquisition of the Energy Trading Business and $150 million of AGC debt.
In June 2001, Monongahela Power and Allegheny Energy transferred
generating assets to us totaling 523 MW. As part of this transfer, our members'
equity increased by $173.9 million and long-term debt increased by
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$15.9 million. See Note 5 to our consolidated financial statements for the
period ended September 30, 2001, for additional details.
In May 2001, we financed the purchase of the Midwest Assets with cash
received from Allegheny Energy through its sale of 14.26 million shares of
common stock priced at $48.25 per share and a bridge loan for $550 million from
a group of credit providers. Allegheny Energy contributed $175 million of the
proceeds from its sale of common stock and loaned $325 million to us under an
interest-bearing note, which we expect to retire with the proceeds from the
initial public offering discussed above.
In November 2001, we completed an operating lease transaction, known as
the St. Joseph lease transaction, in connection with a 630 MW intermediate-load
and peaking natural gas-fired facility located in St. Joseph County, Indiana.
Commercial operation is expected to begin in 2003 for the peaking facility and
in 2005 for the intermediate-load facility. The St. Joseph lease transaction was
structured to finance the construction of both the peaking and intermediate
facility with a maximum commitment amount of $460 million. We will lease the
plant from a non-affiliated lessor special purpose entity when the construction
has been completed. Lease payments, to be recorded as rent expense, are
estimated at $2.8 million per month, commencing on final completion of the
entire facility in 2005 and continuing through November 2007. After November
2007, we have the right to negotiate renewal terms or purchase the facility for
the lessor's investment or sell the facility and pay the amount, if any, by
which the lessor's investment exceeds the sale proceeds, up to a maximum
recourse amount of approximately $392 million.
Prior to closing the St.Joseph lease transaction, in April 2001, we
consummated an operating equipment-lease transaction structured to finance the
purchase of turbines and transformers with a maximum commitment amount of $150
million. The St.Joseph lease transaction included a transfer between lessors of
some of the equipment previously financed in this equipment lease. As a result,
the commitment in the equipment lease has been reduced to approximately $43
million. The remainder of the equipment financed in the equipment lease will be
used for another project.
Included in the St.Joseph lease transaction is a loan to us of $380
million from the non-affiliated lessor special purpose entity. We are required
to repay part of the loan monthly during the lease construction period, based on
project cost funding requirements. Loan repayments are estimated as $5.5 million
in 2001, $157.6 million in 2002, $156.8 million in 2003, and $60.1 million in
2004. On the closing date of the lease transaction, we repaid approximately $4.0
million of the loan and used approximately $376.0 million of the net proceeds to
refinance existing affiliated and non-affiliated short-term debt.
On March 16, 2001, we acquired the Energy Trading Business for $489.2
million in cash plus the issuance of a 1.967% equity membership interest in us.
The cash portion of the transaction closed on March 16, 2001, and was financed
by issuing $400 million of 7.80% notes due 2011 and issuing short-term debt for
the balance. By order dated May 30, 2001, the SEC authorized the issuance of an
equity membership interest in us to Merrill Lynch. Effective June 29, 2001, the
transaction was completed and Merrill Lynch now has a 1.967% equity ownership in
us. The purchase agreement for the Energy Trading Business provides that if
Monongahela Power's West Virginia jurisdictional assets have not been
transferred to us by September 2002 or Allegheny Energy has not completed the
initial public offering of our proposed new parent holding company's common
stock by March 2003, Merrill Lynch has the right to require Allegheny Energy to
repurchase all of Merrill Lynch's equity interest in us for $115 million plus
interest calculated from March 16, 2001.
Allegheny Energy also contributed an additional $96.8 million to us
during various dates in the first nine months of 2001.
Letters of credit are purchased guarantees that ensure our performance
or payment to third parties, in accordance with certain terms and conditions,
and amounted to $348.4 million of the $410.8 million available as of September
30, 2001.
We had significant trade credit support commitments related to our
wholesale marketing, energy trading, fuel procurement and risk management
activities as of September 30, 2001. To the extent that we do not maintain an
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investment grade credit rating, we would be required to provide alternative
and/or additional collateral to certain counterparties. Such collateral might be
in the form of letters of credit or additional deposits.
When we were formed in November 1999, we assumed $230.8 million of
pollution control debt from West Penn in connection with the transfer of the
West Penn generating assets to us. In December 1999, we assumed debt in the form
of a $130 million bank term loan in connection with the purchase of 276 MW of
unregulated generating capacity at Fort Martin Unit No. 1 from an Allegheny
Energy unregulated subsidiary. The interest rate on the $130 million term loan
in 1999 was priced at LIBOR plus a spread and was reset quarterly. This debt was
refinanced in October 2000 with short-term debt. On August 1, 2000, we assumed
$104.2 million of pollution control debt in connection with the transfer to us
of Potomac Edison's generating assets.
In June 2000, Potomac Edison issued $80 million floating rate private
placement notes, due May 1, 2002, assumable by us upon our acquisition of
Potomac Edison's Maryland jurisdictional generating assets. In August 2000,
after the Potomac Edison generating assets were transferred to us, the notes
were remarketed as our floating rate (three-month LIBOR plus .80%) notes with
the same maturity date. We did not receive additional proceeds.
In November 2000, we consummated an operating lease transaction relating
to the construction of a 540 MW combined-cycle generating plant located in
Springdale, Pennsylvania. This transaction was structured to finance the
construction of the plant with a maximum commitment amount of $318.4 million.
Upon completion of the plant, a special purpose entity will lease the plant to
us. Lease payments, to be recorded as rent expense, are estimated at $1.9
million per month, commencing during the second half of 2003 through 2005.
Subsequently, we have the right to negotiate up to two five-year renewal terms
or purchase the plant for the lessor's investment or sell the plant and pay the
difference between the proceeds and the lessor's investment up to a maximum
recourse amount of approximately $275 million.
SIGNIFICANT CONTINUING ISSUES
ELECTRIC ENERGY COMPETITION
The electricity supply segment of the electric industry in the United
States is becoming increasingly competitive. The national Energy Policy Act of
1992 deregulated the wholesale exchange of power within the electric industry by
permitting the Federal Energy Regulatory Commission, or FERC, to compel electric
utilities to allow third parties to sell electricity to wholesale customers over
their transmission systems. We continue to be an advocate of federal legislation
to remove artificial barriers to competition in electricity markets, avoid
regional dislocations and ensure level playing fields.
In addition to the wholesale electricity market becoming more
competitive, the majority of states have taken active steps towards allowing
retail customers the right to choose their electricity supplier.
Our parent, Allegheny Energy, is at the forefront of state-implemented
retail competition, having negotiated settlement agreements in all of the states
Monongahela Power, Potomac Edison and West Penn serve. Pennsylvania, Maryland
and Ohio have retail choice programs in place. West Virginia's Legislature has
approved a deregulation plan for Monongahela Power pending additional
legislation regarding tax revenues for state and local governments. Virginia and
West Virginia are in the process of developing rules to implement customer
choice.
The regulatory environment applicable to our generation businesses will
continue to undergo substantial changes, on both the federal and state level.
These changes have significantly affected the nature of the power industry and
the manner in which its participants conduct their 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 us
in ways that we cannot predict. Some markets, such as in California, have
recently experienced interruptions of supply and price volatility. These
interruptions of supply and price volatility have been the subject of a
significant amount of press coverage, much of which has been critical of the
restructuring initiatives. In some of these markets, including California,
government agencies and other interested parties have made proposals to
re-regulate areas of these markets that have previously been deregulated, and,
in California, legislation has been passed placing a moratorium on the sale of
generating
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plants by regulated utilities. Proposals to re-regulate the wholesale
power market also have been made at the federal level. Proposals of this sort,
and legislative or other attention to the electric power restructuring process
in the states in which we currently, or may in the future, operate, may cause
this process to be delayed, discontinued, or reversed, which could have a
material adverse effect on our results of operations or our strategies.
ENVIRONMENTAL ISSUES
The Environmental Protection Agency's, or EPA, nitrogen oxides, or NOx,
State Implementation Plan, or SIP, call regulation has been under litigation
and, on March 3, 2000, the District of Columbia Circuit Court of Appeals issued
a decision that upheld the regulation. However, state and industry litigants
filed an appeal of that decision in April 2000. On June 23, 2000, the Court
denied the request for the appeal. Although the Court did issue an order to
delay the compliance date from May 1, 2003 until May 31, 2004, both the Maryland
and Pennsylvania state rules to implement the EPA NOx SIP call regulation still
require compliance by May 1, 2003. West Virginia has issued a proposed rule that
would require compliance by May 31, 2004. However, the EPA Section 126 petition
regulation also requires the same level of NOx reductions as the EPA NOx SIP
call regulation with a May 1, 2003 compliance date. The EPA Section 126 petition
rule is also under litigation in the District of Columbia Circuit Court of
Appeals. A Court decision in May 2001 upheld the rule. In August 2001, the Court
issued an order that suspends the Section 126 petition rule May 1, 2003
compliance date pending EPA review of growth factors used to calculate the state
NOx budgets. Our compliance with such stringent regulations will require the
installation of expensive post-combustion control technologies on most of our
power stations. During the period 2002 through 2004, we expect to spend
approximately $162.3 million in connection with the installation of emission
control equipment at our facilities. This amount does not include expenditures
relating to the remaining generating assets that we expect to have transferred
to us from Monongahela Power.
On August 2, 2000, Allegheny Energy received a letter from the EPA
requiring it to provide certain information on the following 10 electric
generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's
Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island.
Monongahela Power and we now own these electric power generating stations. The
letter requested information under Section 114 of the federal Clean Air Act to
determine compliance with federal Clean Air Act and state implementation plan
requirements, including potential application of the federal New Source Review.
In general, these standards can require the installation of additional air
pollution control equipment upon the major modification of an existing facility.
Allegheny Energy submitted these records in January 2001. The eventual outcome
of the EPA investigation is unknown.
Similar inquiries have been made of other electric utilities and have
resulted in enforcement proceedings being brought in many cases. We believe our
generating facilities have been operating in accordance with the Clean Air Act
and the rules implementing the Act. The experience of other utilities, however,
suggests that, in recent years, the EPA may well have revised its interpretation
of the rules regarding the determination of whether an action at a facility
constitutes routine maintenance, which would not trigger the requirements of the
federal New Source Review, or a major modification of the facility, which would
require compliance with the federal New Source Review. If the federal New Source
Review were to be applied to these generating stations, in addition to the
possible imposition of fines, compliance would entail significant expenditures.
In December 2000, the EPA issued a decision to regulate coal- and
oil-fired electric utility mercury emissions under Title III, Section 112 of the
1990 Clean Air Act Amendments. The EPA plans to issue a proposed regulation by
December 2003 and a final regulation by December 2004. The timing and level of
required mercury emission reductions are unknown at this time.
RIGHT-TO-KNOW
On June 27, 2001, Allegheny Energy submitted its 2000 Toxic Release
Inventory with the EPA and appropriate state government agencies, reporting 32.8
million pounds of total releases for the calendar year 2000. The inventory is
part of the Emergency Planning and Community Right-to-Know Act, which requires
Allegheny Energy to report estimated annual releases of certain chemical
substances entering into the environment through the process of burning fossil
fuels to make electricity. The releases reported by Allegheny Energy are trace
elements that occur naturally in coal, as well as stack gases formed during the
combustion process. These trace elements have always been present in the
electricity generation process. Allegheny Energy has made no change in the way
it
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generates electricity. However, the EPA has changed its rules for reporting
these materials and added new database reporting requirements. Because of these
changing requirements and Allegheny Energy's customers' increasing demand for
electricity, which also increases the amount of coal Allegheny Energy burns, the
estimated releases of chemicals reported for Allegheny Energy's generating
facilities increased during the 2000 calendar year.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 was subsequently amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB
Statement No. 133" and SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities - an amendment of FASB Statement No.
133." Effective January 1, 2001, we implemented the requirements of these
accounting standards.
These statements establish accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. They require that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. The statements require that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in earnings or other comprehensive income and requires that a company
formally document, designate, and assess the effectiveness of transactions that
receive hedge accounting. SFAS No. 133 is expected to increase the volatility in
reported earnings and other comprehensive income.
On January 1, 2001, we recorded an asset of $1.5 million on our balance
sheet based on the fair value of the two cash flow hedge contracts. An
offsetting amount was recorded in other comprehensive income as a change in
accounting principle as provided by SFAS No. 133. We have two principal risk
management objectives regarding these cash flow hedge contracts. First, we have
a contractual obligation to service the instantaneous demands of our customers.
When this instantaneous demand exceeds our electric generating capability, we
must enter into contracts providing for the purchase of electricity to meet this
shortage. Second, the price of electricity is subject to price volatility. This
volatility is the result of many forces, including the weather, and tends to be
the highest during the summer months. To ensure that energy market movements do
not cause a significant degradation in earnings, we enter into fixed price
electricity purchase contracts.
The amounts accumulated in other comprehensive income related to these
contracts were reclassified to earnings during July and August of 2001, when the
hedged transactions were executed. A loss of $5 million, before tax ($3.1
million net of tax), was reclassified to purchased energy and transmission
during the third quarter of 2001.
We also have certain option contracts that meet the derivative criteria
in SFAS No. 133, which did not qualify for hedge accounting. On January 1, 2001,
we recorded an asset of $0.1 million and a liability of $52.4 million on our
balance sheet based on the fair value of these contracts. The majority of this
liability was related to one contract. The terms of this three-year contract
entered into on January 1, 1999, provides the counterparty with the right to
purchase, at a fixed price, 270 MW of electricity per hour until December 31,
2001. The fair value of this contract represented a liability of approximately
$52.3 million on January 1, 2001. The liability associated with this contract
will reduce to zero at December 31, 2001, with the expiration of the contract.
The fair value of these contracts will fluctuate over time due to changes in the
underlying commodity prices that are influenced by various factors, including
the weather and availability of regional electric generation and transmission
capacity. In accordance with SFAS No. 133, we recorded a charge of $31.1 million
against earnings net of the related tax effect ($52.3 million before tax) for
these contracts as a change in accounting principle on January 1, 2001. As of
September 30, 2001, the net fair value of these contracts was $1.1 million. The
total change in fair value of $51.2 million for these contracts during the first
nine months of 2001 was recorded as an unrealized gain in "Operating Revenues -
Wholesale" on the consolidated statement of operations.
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks associated with commodity prices and
interest rates. The commodity price risk exposure results from market
fluctuations in the price and transportation costs of electricity, natural gas,
and other commodities. The interest rate risk exposure results from changes in
interest rates as a result of interest rate swaps, commercial paper, and
fixed-rate debt. We are mandated by Allegheny Energy's Board of Directors to
engage in a program that systematically identifies, measures, evaluates, and
actively manages and reports on market-driven risks.
Of our commodity-driven risks, we are primarily exposed to risks
associated with the wholesale marketing of electricity, including the
generation, fuel procurement, power marketing, and trading of electricity. Our
wholesale activities principally consist of marketing and trading
over-the-counter forward and NYMEX future contracts for the purchase and sale of
electricity and natural gas. The majority of these contracts represent
commitments to purchase or sell electricity and natural gas at fixed prices in
the future. Except for the NYMEX contracts, these contracts require physical
delivery of electricity and natural gas.
We also use option contracts to buy and sell electricity and natural gas
at fixed prices in the future. These option contracts are generally entered into
for risk management purposes. The risk management activities focus on management
of volume risks (supply), operational risks (plant outages), and market risks
(energy prices).
We have entered into long-term contractual obligations for sales of
electricity to other load-serving entities, municipalities, retail load
aggregators, affiliates and other entities:
o in March 2001, we acquired the Energy Trading Business including
the contractual right to control 1,000 MW of generation in
California. See "--TRANSFER AND ACQUISITION OF GENERATING ASSETS
AND GENERATING CAPACITY SINCE FORMATION--ACQUISITION OF GLOBAL
ENERGY MARKETS";
o in March 2001, we signed a power sales agreement with the
California Department of Water Resources, the electricity buyer
for the state of California. The $4.5 billion contract is for a
period through December 2011. Under the terms of the agreement,
we have committed to sell up to 1,000 MW of electricity,
primarily through our contractual control of 1,000 MW of
generation capacity in California, which we acquired as part of
the acquisition of the Energy Trading Business. See "--TRANSFER
AND ACQUISITION OF GENERATING ASSETS AND GENERATING CAPACITY
SINCE FORMATION--RECENT POWER SALES AGREEMENTS";
o in May 2001, we signed a 15-year agreement with Las Vegas
Cogeneration II, L.L.C. for 222 MW of generating capacity,
beginning in the third quarter of 2002. See "--ANNOUNCED
CONSTRUCTION AND DEVELOPMENT PLANS AND ASSET TRANSFERS -
CONTRACTUAL CONTROL OF CAPACITY";
o in August 2001 we were a successful bidder to supply Baltimore
Gas & Electric Company with electricity from July 2003 through
June 2006. See "--RECENT POWER SALES AGREEMENTS";
o in November 2001, we announced that under the terms of a joint
venture arrangement, we will acquire the contractual right to
control 79 MW of a barge mounted, natural gas-fired combustion
turbine generating facility. See "--ANNOUNCED CONSTRUCTION AND
DEVELOPMENT PLANS AND ASSET TRANSFERS--CONTRACTUAL CONTROL OF
CAPACITY"; and
o we have entered into power sales agreements to supply power to
West Penn, Potomac Edison with respect to its Maryland and
Virginia customers and Monongahela Power with respect to its Ohio
customers through various periods up to 2008. Under these
agreements, we are obligated to provide these regulated utility
affiliates with the amount of electricity, up to their
provider-of-last-resort retail load, that they may demand. These
power sales agreements currently require a significant portion of
the normal operating capacity of our fleet of transferred
generating assets, but we expect that this will decrease over
time. Our power sales agreements with West Penn, Monongahela
Power and Potomac Edison with respect to its Maryland and
Virginia customers have a fixed price as well as a market-
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based pricing component. As the amount of generating capacity
delivered under these agreements decreases, the amount of
electricity sold under these contracts that is subject to market
price escalates each year during the transition periods. We
expect that when the transition periods end, West Penn,
Monongahela Power and Potomac Edison will pay us market rates for
the entire amount of electricity provided to them.
Allegheny Energy has a Corporate Energy Risk Control Policy adopted by
its Board of Directors and monitored by an Exposure Management Committee chaired
by its Chief Executive Officer and composed of its senior management that covers
our operations. An Allegheny Energy risk management group, independent of our
operations, actively measures and monitors the risk exposures to ensure
compliance with the policy and periodically reviews this policy.
To manage our financial exposure to commodity price fluctuations in our
energy trading, fuel procurement, power marketing, and risk management
activities, we routinely enter into contracts, such as electricity purchase and
sale commitments, to hedge our risk exposure. However, we do not hedge the
entire exposure of our operations from commodity price volatility for a variety
of reasons. To the extent we do not hedge against commodity price volatility,
our results of operations and financial position may be affected either
favorably or unfavorably by a shift in the future price curves.
CREDIT RISK. Credit risk is defined as the risk that a counterparty to a
transaction will be unable to fulfill its contractual obligations. The credit
standing of counterparties is established through the evaluation of the
prospective counterparty's financial condition, specified collateral
requirements where deemed necessary, and the use of standardized agreements,
which facilitate netting of cash flows, associated with a single counterparty.
Financial conditions of existing counterparties are monitored on an ongoing
basis. Our independent risk management group described above oversees credit
risk. As of September 30, 2001, we have received $27.6 million of collateral
from counterparties involved in our energy trading activities.
We are engaged in various trading activities in which counterparties
primarily include electric and gas utilities, independent power producers, oil
and gas exploration and production companies, and energy marketers. In the event
the counterparties do not fulfill their obligations, we may be exposed to credit
risk. The risk of default depends on the creditworthiness of the counterparty or
issuer of the instrument. We have a concentration of customers in the electric
and gas utility and oil and gas exploration and production industries. These
concentrations in customers may impact our overall exposure to credit risk,
either positively or negatively, in that the customers may be similarly affected
by changes in economic or other conditions. Based on our policies and exposures,
we do not currently anticipate a materially adverse effect on financial position
or results of operations as a result of counterparty nonperformance.
MARKET RISK. Market risk arises from the potential for changes in the
value of energy related to price and volatility in the market. We reduce these
risks by using our generating assets and contractual generation under our
control to back positions on physical transactions. Market exposure and credit
risk have established aggregate and counterparty limits that are monitored
within the guidelines of the Corporate Energy Risk Control Policy. We evaluate
commodity price risk, operational risk, and credit risk in establishing the fair
value of commodity contracts.
We use various methods to measure our exposure to market risk, including
a value at risk model, or VaR. VaR is a statistical model that attempts to
predict risk of loss based on historical market price and volatility data over a
given period of time. Our VaR calculation includes all contracts, whether
financially or physically settled, associated with our wholesale marketing and
trading of electricity, natural gas, and other commodities. We calculate VaR
including our generating capacity and the power sales agreements for the
provider-of-last-resort retail load obligations of Allegheny Energy's regulated
utility subsidiaries. The VaR calculation does not include positions beyond
three years for which there is a limited observable, liquid market and commodity
price exposure related to the procurement of fuel for our own generation. We
believe that this represents the most complete calculation of our value at risk.
We calculate VaR using a variance/covariance technique that models
option positions using a linear approximation of their value based upon the
option's delta equivalents. Due to inherent limitations to VaR, including the
use of approximations to value options, subjectivity in the choice of
liquidation period and reliance on
-46-
historical data to calibrate the model, the VaR calculation may not accurately
reflect our market risk exposure. As a result, the actual changes in our market
risk sensitive instruments could differ from the calculated VaR, and such
changes could have a material impact on our financial results.
The VaR amount represents the potential loss in fair value from the
market risk sensitive positions described above over a one-day holding period
with a 95% confidence level. As of September 30, 2001, our VaR was $14.7 million
including our generating capacity and our power sales agreements with Allegheny
Energy's regulated utility subsidiaries. At December 31, 2000, our VaR was $38.7
million. This calculation included contracts and positions for the next 12
months and our generating assets, our power sales agreements with Allegheny
Energy's regulated utility subsidiaries, retail and other similar obligations.
The decrease in VaR for the first nine months of 2001 is primarily due to a
reduction in our open power positions in the on-peak period in the
forward-looking 12 months.
We also calculated VaR using the full term of all trading positions but
excluding our generating capacity and our power sales agreements for the
provider-of-last-resort retail load obligations of Allegheny Energy's regulated
utility subsidiaries. This calculation includes positions beyond three years for
which there is a limited observable, liquid market. As a result, this
calculation is based upon management's best estimates and modeling assumptions,
which could materially differ from actual results. As of September 30, 2001,
this calculation yielded a VaR of $16.5 million.
We have entered into long-term arrangements with terms of 12 months or
longer to purchase approximately 90% of our base fuel requirements for our owned
generation in 2001. We depend on short-term arrangements and spot purchases for
our remaining requirements. Until 2005, we expect to meet our total coal
requirements for our generating assets under existing contracts or from current
suppliers.
-47-
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
OUR COMPANY
We are a rapidly growing merchant energy company with 14,687 megawatts,
or MW, of generating capacity owned, controlled, under construction or in
development, pending transfer from affiliates or planned as facility expansions.
We currently own 8,796 MW in the Eastern and Midwestern regions of the United
States and have the contractual right to control 1,000 MW in California. We are
expanding our generation fleet by 2,731 MW through the announced construction
and development of new facilities, acquisition of contractual rights to control
generating capacity and planned expansions to existing facilities. It is our
goal to complete the transfer of an additional 2,160 MW in the Eastern markets
from our parent, Allegheny Energy, Inc. and its subsidiaries. We manage all of
our generation assets as an integrated portfolio with our energy trading, fuel
procurement, power marketing and risk management activities.
We were formed in November 1999 to take advantage of the opportunity to
transfer to us at net book value some of the generation assets of the regulated
utility subsidiaries of our parent, Allegheny Energy, as a result of economic
factors and federal and state legislative and regulatory changes related to the
development of competitive markets. To date, 6,230 MW of generating assets have
been transferred to us by the regulated utility subsidiaries of Allegheny
Energy. These transferred assets had a net book value at the time of transfer to
us of approximately $257 per kW and had low fuel costs and low variable
operating and maintenance costs for the coal-fired facilities of approximately
$17 per MWh. These cost characteristics position our transferred generating
assets among the lowest cost generating assets in the United States.
Approximately 2,160 MW of generating capacity from Allegheny Energy and its
subsidiaries, including 2,111 MW from Monongahela Power, is still awaiting final
legislative or regulatory authorization for transfer to us.
These transferred generating assets consist primarily of low-cost,
coal-fired, base-load facilities strategically located in the expanded wholesale
and retail electricity market made possible by the creation of PJM-West.
PJM-West is a new contractual arrangement that we expect will be operational in
the first quarter of 2002 and which we expect will integrate, for the first
time, our traditional regional markets in the East Central Area Reliability
Region and the liquid regional trading markets of the Pennsylvania-New
Jersey-Maryland market, commonly known as the PJM market. Altogether, we now
have access to six of the most liquid trading hubs east of the Mississippi
River.
Through our acquisition, construction and development efforts, we are
simultaneously growing our generation capacity and diversifying our portfolio of
assets among base-load, intermediate or peaking capacity, mix of fuel and
geographic location. Many of our recently announced acquisitions and
construction and development plans involve natural gas-fired peaking or
intermediate dispatch facilities located in the Midwest and Southwestern regions
of the United States.
We have taken significant steps to develop a national business with the
acquisition of the Energy Trading Business from Merrill Lynch and our
acquisition and construction and development activities in the Eastern,
Midwestern and Southwestern regions of the United States which are markets that
have capacity shortages and attractive competitive characteristics. We have
construction and development projects under way in Arizona, Indiana,
Pennsylvania and Virginia.
SIGNIFICANT RECENT DEVELOPMENTS
CORPORATE RESTRUCTURING
In November 2001, we and our parent, Allegheny Energy, filed an
application with the SEC seeking authorization under the Public Utility Holding
Company Act of 1935 to restructure our corporate organization by creating a new
Maryland holding company into which we will then merge. We will thereby be
changed from a Delaware limited liability company into a Maryland corporation.
We and our parent, Allegheny Energy, also sought authorization to merge
Allegheny Energy Global Markets, one of our wholly-owned subsidiaries, into this
new Maryland holding company, which will then continue to conduct the energy
commodity marketing and trading
-48-
activities of Allegheny Energy Global Markets. On December 31, 2001, we received
SEC approval to effect this reorganization.
INITIAL PUBLIC OFFERING AND DISTRIBUTION. On July 23, 2001, Allegheny
Energy filed an application with the SEC seeking authorization under the Public
Utility Holding Company Act of 1935 to:
o effect an initial public offering of up to 18% of the common
stock of the new Maryland holding company, which we intend to
complete when favorable market and other conditions exist; and
o distribute the remaining common stock of the new Maryland holding
company owned by Allegheny Energy and not sold in the initial
public offering to the stockholders of Allegheny Energy on a
tax-free basis within 24 months following the completion of the
initial public offering.
MIDWEST ASSETS ACQUISITION. In May 2001, we acquired three natural
gas-fired generating facilities totaling 1,710 MW of peaking capacity from Enron
North America Corp. These generating facilities include the 656 MW Lincoln
Energy Center plant in Illinois, the 508 MW Wheatland plant in Indiana and the
546 MW Gleason plant in Tennessee. The value of these assets is enhanced by
their location, which allows us to charge fees for ancillary services to the
transmission systems in these regions, in addition to providing energy in
periods of peak demand.
ENERGY TRADING BUSINESS. In March 2001, we acquired the energy commodity
marketing and trading business of Merrill Lynch Capital Services, Inc., which we
refer to as the Energy Trading Business and which now operates as Allegheny
Energy Global Markets, LLC, one of our wholly-owned subsidiaries. This Energy
Trading Business helps us optimize our portfolio of generating assets by
significantly enhancing our wholesale marketing, energy trading, fuel
procurement and risk management activities. The Energy Trading Business has also
expanded our expertise in nation-wide trading, fuel procurement, market analysis
and risk management. We are therefore better able to identify opportunities to
expand our acquisition and development activities and to compete outside our
traditional regions. In addition, the Energy Trading Business enables us to
provide customized energy management solutions to wholesale, industrial and
commercial customers.
RECENT POWER SALES AGREEMENTS. In March 2001, we entered into a power
sales agreement with the California Department of Water Resources. Under this
agreement, we have committed to supply the State of California with electricity
through December 2011. Deliveries of power have begun, with contract volumes
varying from 150 MW to 500 MW through December 2004. For the last seven years of
the agreement, the contract volume will be fixed at 1,000 MW. We plan to supply
this power primarily through our contractual control of 1,000 MW of generating
capacity in California, which we acquired as part of the acquisition of the
Energy Trading Business.
In August 2001, we were a successful bidder to supply Baltimore Gas &
Electric Company with electricity from July 2003 through June 2006. We are
committed to supply Baltimore Gas & Electric Company with an amount needed to
fulfill 10% of its provider-of-last-resort obligations.
OUR STRATEGY
Our strategy is to continue to transform our company from a regional
merchant market operator of formerly regulated utility generation assets to a
competitive national energy merchant with energy marketing and customized energy
management solutions capabilities for our customers. In addition to our Eastern
market, we believe the Midwestern and Southwestern markets provide us with
significant growth opportunities. We plan to implement our growth plan with the
following strategies:
o CONTINUE TO TRANSFORM FROM A REGIONAL TO A NATIONAL PRESENCE IN
THE UNITED STATES. We plan to pursue attractive opportunities for
expanding our generation capacity through acquisitions,
development and other contractual control arrangements in
targeted regions of the United States. Contractual control
arrangements generally allow us to maintain a lower capital
commitment and permit a faster time-to-market than if we were to
build facilities ourselves.
Since January 2000, we have announced:
-49-
-- the purchase of the Midwest Assets consisting of three
natural gas-fired merchant generating facilities totaling
1,710 MW of peaking capacity in the Midwest from Enron;
-- the installation of five 44 MW simple-cycle combustion
turbines in various parts of Pennsylvania;
-- the construction of a 540 MW combined-cycle facility in
Springdale, Pennsylvania under existing contractual control
arrangements with an expected commercial operation date of
2003;
-- the construction and leasing arrangement of a 630 MW
intermediate-load and peaking natural gas-fired facility in
St. Joseph County, Indiana with expected commercial
operation dates of 2003 for the peaking facility and 2005
for the intermediate-load facility;
-- the construction of a 1,080 MW base-load natural gas-fired,
combined cycle peaking facility in La Paz County, Arizona
with an expected commercial operation date of 2005;
-- the contractual right to control 222 MW of generation
capacity from a natural gas-fired facility, currently under
construction by a third party, in Las Vegas, Nevada
beginning in the third quarter of 2002; and
-- the construction of a joint development project through
which we will obtain 44 MW of new simple-cycle combustion
turbines located in Buchanan County in southwest Virginia.
o EXPAND AND DIVERSIFY OUR BASE-LOAD, COAL-FIRED GENERATION FLEET
TO INCLUDE A COMBINED COAL AND NATURAL GAS-FIRED PORTFOLIO OF
ASSETS WITH DISPATCH AND GEOGRAPHIC DIVERSITY. Through our
acquisition, construction and development program, we are adding
new peaking and intermediate units to diversify our generating
asset and fuel mix portfolios geographically and by dispatch
type. Our natural gas strategy includes the ownership and control
of power plants, natural gas reserves, natural gas transportation
and storage capacity in targeted regions throughout the United
States.
o TRANSFER OF ADDITIONAL GENERATING ASSETS FROM ALLEGHENY ENERGY
AFFILIATES. In June 2001, Monongahela Power, one of Allegheny
Energy's regulated utility subsidiaries, transferred
approximately 352 MW of generating assets to us at net book
value. Monongahela Power's remaining generation assets, 2,111 MW,
which serve customers in West Virginia, will not be transferred
until tax changes related to the deregulation of the retail power
market in West Virginia have been passed by the West Virginia
Legislature or the West Virginia Public Service Commission
otherwise takes regulatory action. Subject to reaching a
settlement with the West Virginia Public Service Commission or
receiving authorization from the West Virginia Legislature and
the SEC releasing jurisdiction over the proposed transfer,
Monongahela Power intends to transfer the remaining assets as
soon as possible. After all of Monongahela Power's generating
assets have been transferred to us, we will own all of the
generating assets previously owned by the regulated utility
subsidiaries of Allegheny Energy.
We also anticipate that an additional 49 MW of generation
capacity, including assets at the Hunlock Creek, Pennsylvania
facility will be transferred to us once our ownership of this
capacity has been approved by the SEC.
o MANAGE OUR POWER GENERATION, ENERGY TRADING, FUEL PROCUREMENT,
POWER MARKETING AND RISK MANAGEMENT ACTIVITIES. We have combined
the energy trading, fuel procurement, power marketing and risk
management expertise of the Energy Trading Business with our
existing skills in these areas and with our historical experience
as a low-cost operator of generation facilities to:
-- maximize the value of and optimize the performance of our
low-cost generating assets that were transferred to us and
were previously operated as part of vertically integrated
utilities and to shift these assets to "best-in-class"
merchant market performance;
-50-
-- trade natural gas, source fuel supplies, help control our
fuel and dispatch risk and better control our costs of
production. As a result, we expect to be able to increase
our earnings and optimize our portfolio of power sales to
our wholesale customers;
-- enhance development and acquisition opportunities; and
-- enhance our ability to develop and offer customized energy
management solutions and comprehensive risk management
services for our wholesale customers.
o MAINTAINING A STRONG CREDIT POSITION. It is our objective to
maintain an investment grade credit rating after the initial
public offering and distribution of shares of common stock to
Allegheny Energy stockholders.
OUR MARKET OPPORTUNITIES
We believe that there will be significant opportunities for us to
rapidly expand our generation portfolio over the next five to ten years.
Capacity-constrained regions require new generation construction as older, less
efficient plants are retired, giving us an opportunity to grow through new
construction, generation asset divestitures and industry consolidation.
The continuing deregulation of the electric utility industry in the
United States will also create opportunities to provide services to end users of
electricity and to provide energy or energy-related services to wholesale
customers such as power resellers that require energy sources or risk mitigation
services. We believe that our generation asset portfolio and our risk management
skills will also position us to provide comprehensive energy solutions to the
increasing number of electric distribution companies that have sold their
generation assets and must obtain power in the competitive market place. Risk
management skills like ours will be essential to help these companies hedge
their customers' exposure to volatile electricity and energy prices.
As owner of the generating assets that were transferred to us from
Allegheny Energy's regulated utility subsidiaries before deregulation, we
believe that we have significant insights into the markets and regions we have
historically served. Local knowledge of load management, fuel availability and
transportation, transmission, siting and permitting provide us with advantages
compared to out-of-region generation companies. The regulated utility
subsidiaries of Allegheny Energy have recently received preliminary approval
from FERC to join the PJM market through a new contractual arrangement called
PJM-West. We believe PJM-West will integrate, for the first time, our
traditional regional markets in the East Central Area Reliability Region and the
liquid regional trading markets of the PJM market by improving our access to
these markets. We expect that PJM-West, and any future expanded markets created
in the Northeastern regions of the United States, will enhance the value of our
low-cost generation asset portfolio by expanding our market-reach with lower
transmission costs.
Our acquisition of the Energy Trading Business will allow us to better
compete outside our traditional regions with incumbent generation companies and
other merchant generation companies through our development and acquisition
activities. In these markets, we will have the benefit of our recently acquired
expertise in nation-wide trading, fuel procurement, market analysis and risk
management.
COMPETITIVE ADVANTAGES
We believe that we are well positioned to become one of the premier
national energy merchants because of our large cost-efficient generation fleet,
our extensive market knowledge and risk management expertise and a strong credit
position. We have significant competitive advantages, including:
o STRATEGIC LOCATION AND COST EFFICIENT TRANSFERRED GENERATING ASSETS.
We currently own 8,796 MW of capacity of which 6,230 MW have been
transferred to us by Allegheny Energy's regulated utility
subsidiaries. The competitive advantages of these transferred
generating assets are as follows:
-51-
-- they were transferred to us at a net book value at the time of
transfer of approximately $257 per kilowatt, or kW;
-- they are primarily coal-fired, have a low fuel cost and low
variable operating and maintenance cost totaling approximately
$17 per MWh, and have attractive transportation costs due to
their proximity to our primary fuel source in the Appalachian
coal-mining region. Our use of coal-fired generation facilities
and the relatively low cost of coal make us competitive in a
market where the price of electricity is increasingly determined
by the cost of natural gas. Increases in the cost of natural gas
generally mean lower profit margins for gas-fired facilities
and/or higher electricity prices. We are positioned to take
advantage of this because, to date, changes in the cost of
natural gas have not had a significant impact on coal prices or
the production of power by coal-fired facilities;
-- most of these assets are in the East Central Area Reliability
Region, strategically located in the expanded wholesale and
retail electricity market made possible by the creation of
PJM-West. PJM-West is a new contractual arrangement that we
expect will be operational in the first quarter of 2002 and which
we expect will integrate, for the first time, our traditional
regional markets in the East Central Area Reliability Region and
the liquid regional trading markets of the PJM market.
Altogether, we now have access to six of the most liquid trading
hubs east of the Mississippi River; and
-- most of the personnel that operated these generating assets for
the regulated utility subsidiaries of Allegheny Energy continue
to operate these assets for us. We believe we can build on this
operating experience in a competitive marketplace by offering
greater rewards and incentives to these employees. We also
believe we can transfer our experience and expertise in operating
generating facilities to new plants we acquire and develop.
o PREMIER ENERGY TRADING, FUEL PROCUREMENT, POWER MARKETING AND RISK
MANAGEMENT SKILLS. Our energy trading, fuel procurement, power
marketing and risk management skills allow us to optimize our
portfolio of generating assets by:
-- taking advantage of and profiting from regional supply and demand
patterns, capacity shortages, transmission constraints and
weather throughout the United States;
-- helping us identify attractive opportunities for expanding
generating capacity through acquisitions, development or
contractual arrangements; and
-- giving us the ability to opportunistically trade and source fuel
for our generating assets from various locations.
o DEMONSTRATED ABILITY TO EXPAND INTO COMPETITIVE MARKETS. Since our
formation in November 1999, we have demonstrated our ability to
transform our company from a regional generation company to a
competitive national energy merchant by:
-- implementing approved deregulation settlements in the various
states applicable to our business. These settlements allowed the
transfer to us of generating assets in 1999, 2000 and 2001 from
the regulated utility subsidiaries of Allegheny Energy. Most of
these transferred generating assets are located in the expanded
wholesale and retail electricity market made possible by the
creation of PJM-West;
-- acquiring the Energy Trading Business from Merrill Lynch in March
2001;
-- acquiring three natural gas-fired generating facilities totaling
1,710 MW of capacity in the Midwest from Enron in May 2001;
-52-
-- announcing the construction and development of 2,382 MW of
capacity located in the Eastern, Midwestern and Southwestern
markets of the United States; and
-- signing long-term contractual control arrangements of
approximately 1,300 MW of generation capacity in the Eastern and
Southwestern markets of the United States.
o STRONG CREDIT POSITION. We currently have senior unsecured debt credit
ratings of Baa1 from Moody's and BBB+ from Standard & Poor's and
Fitch. We believe our strong credit position and credit ratings:
-- provide us with financial flexibility that will be important as
we grow our business;
-- give Allegheny Energy Global Markets a stronger credit position
compared to less highly rated industry participants when it
enters into transactions with counterparties; and
-- reduce borrowing costs and credit amounts needed to cover risk
exposures compared to less highly rated industry participants.
OUR MARKETS
OUR GENERATION FACILITIES
As of September 30, 2001, we owned or controlled electric power
generation facilities with an aggregate net generating capacity of 9,796 MW. We
also had 2,160 MW of generating capacity pending approval for transfer to us
from Allegheny Energy affiliates. We have also planned expansions to existing
facilities and announced definitive agreements and construction plans for 2,731
MW of generating capacity. The following table describes:
o our generating assets as of September 30, 2001;
o generating assets currently owned by Monongahela Power, a regulated
utility subsidiary of Allegheny Energy, to be transferred to us;
o other generating assets to be transferred to us from nonregulated
affiliates;
o planned expansions to existing facilities; and
o our new projects under construction or in development.
-53-
MONONGAHELA POWER
ASSETS AWAITING ASSETS FROM
TRANSFER, SUBJECT OTHER
TO LEGISLATIVE OR AFFILIATES OF
ALLEGHENY REGULATORY ACTION ALLEGHENY
ENERGY SUPPLY IN WEST VIRGINIA ENERGY AWAITING
STATE STATIONS FUEL TYPE (MW) (MW)(1)(3) TRANSFER (MW)(3) TOTAL (MW)
- ----------- ------------------------- ------------ ----------------- ------------------- ----------------- -----------------
EASTERN ASSETS
==============
CORE ASSETS:
WV Albright(2) Coal 108 184 292
PA Armstrong Coal 356 356
WV Ft. Martin Coal 619 212 831
WV Harrison Coal 1,535 415 1,950
PA Hatfield's Ferry Coal 1,310 400 1,710
PA Mitchell Coal 288 288
OH & IN Ohio Valley Electric Coal 202 78 280
Corp.(2)
WV Pleasants Coal 1,012 273 1,285
WV Rivesville(2) Coal 21 121 142
MD Smith Coal 116 116
WV Willow Island(2) Coal 36 207 243
VA Bath County(2) Hydro 739 221 960
PA Lake Lynn Hydro 52 52
WV PE Hydro Hydro 3 3
PA Mitchell Oil 154 154
------------ ------------ ------------
Subtotal 6,551 2,111 8,662
OTHER ASSETS:
PA Conemaugh(2) Coal 83 83
WV Ft. Martin Coal 276 276
PA AE 1&2 (Springdale) Natural Gas 88 88
PA AE 8&9 (Gans) Natural Gas 88 88
------------ ------------
Subtotal 535 535
------------ ------------ ------------
TOTAL EASTERN ASSETS 7,086 2,111 9,197
MIDWEST ASSETS
TN Gleason Natural Gas 546 546
IN Wheatland Natural Gas 508 508
IL Lincoln Energy Center Natural Gas 656 656
------------ ------------
Subtotal 1,710 1,710
OTHER GENERATING CAPACITY
=========================
CA Contractual Control(2) Natural Gas 1,000 1,000
------------ ------------
Subtotal 1,000 1,000
NON-REGULATED ASSETS AWAITING TRANSFER FROM OTHER AFFILIATES(3)
===============================================================
PA Hunlock Coal(2) Coal 24 24
PA Hunlock CT(2) Natural Gas 22 22
VA PE Hydro Hydro 3 3
------------ ------------
Subtotal 49 49
------------ ------------
TOTAL GENERATING CAPACITY 9,796 11,956
FUTURE CAPACITY DUE TO POWER STATION 48 48
PLANNED EXPANSIONS
ANNOUNCED CONSTRUCTION AND CONTRACTUAL CONTROL
==============================================
NY Contractual Control Natural Gas 79 79
VA Buchanan County(2) Natural Gas 44 44
NV Contractual Control Natural Gas 222 222
PA Chambersburg Natural Gas 88 88
AZ La Paz Natural Gas 1,080 1,080
PA Springdale Natural Gas 540 540
IN St. Joseph Natural Gas 630 630
------------ ------------
TOTAL ANNOUNCED CONSTRUCTION AND CONTRACTUAL 2,683 2,683
CONTROL
TOTAL GENERATING CAPACITY 12,527 2,111 49 14,687
(1) It is our goal to complete the transfer of these assets from Monongahela
Power upon the implementation of legislation in West Virginia or regulatory
action by the West Virginia Public Service Commission.
(2) Stations in which Allegheny Energy is not the majority owner.
(3) We have requested SEC approval for the transfer of these assets to us.
-54-
Power generation facilities can generally be categorized into three
classes based on the amount of time that the facility is expected to operate and
its variable cost to produce electricity. A facility's variable cost to produce
electricity determines the order in which it is used to meet fluctuations in
electricity demand. Base-load facilities are those that typically have low
variable costs and provide power at all times. Base-load facilities are used to
satisfy the base level of demand for power, or "load," that is not dependent
upon time of day or weather. Intermediate facilities have cost and usage
characteristics in between those of base-load and peaking facilities for daily
and seasonal loads. Peaking facilities have the highest variable cost to
generate electricity and typically are used only during periods of highest
demand for power, such as during extreme weather.
The following graphs set forth our generated energy and generating
capacity by type for the nine months ended September 30, 2001.
Our Generation Capacity by Type For the Our Generated Energy by Type
First Nine Months of 2001 For the First Nine Months of 2001
(9,796 MW)(1) (28,196,381 MWhs)(1)
Base-load 59% Base-load 95%
Peaking 29% Intermediate 3%
Intermediate 12% Peaking 2%
(1) Generation capacity consisting of Eastern assets, Midwest Assets, capacity
under contractual control and capacity from expansions to existing
facilities.
We may select base-load units for an area of relatively high load
factors or stable energy use. Alternatively, we may select peaking units for an
area of relatively low-load factors or high volatility in load demand. The
availability goals of all units are driven by "in-market" availability, that is,
availability during periods when power prices are above the variable cost of
producing power at the facility. We also examine the existing and planned
generating facilities available to serve that demand. We believe that new
peaking, intermediate and base-load units strategically placed throughout
various regions of the country will enhance the value of our supply business by
diversifying our generating asset and our fuel mix portfolio geographically as
well as by equipment type.
Our Eastern assets, as shown in the table on page 54, are primarily the
6,230 MW of base-load, coal-fired generation capacity that was transferred to us
by the regulated utility subsidiaries of Allegheny Energy. We are constructing,
currently have or will have the contractual right to control base-load and
intermediate natural gas-fired generating plants in Arizona, California,
Indiana, Nevada, New York and Pennsylvania. Natural gas-fired generating plants
in these regions have the advantage over other fuel types for new capacity
additions because of their somewhat lower construction costs and the relative
ease of siting new gas-fired plants. We are also constructing or have acquired
natural gas-fired peaking units in Illinois, Indiana, Pennsylvania, Tennessee
and Virginia to capture the profits available in volatile markets and to
diversify our current fuel and geographic mix. In this regard, we believe we are
in a favorable competitive position because peaking facilities have the lowest
installation costs of the three generation classes.
Our predominant use of coal-fired generation facilities and the low cost
of coal provide us with a competitive advantage. Our coal-fired generation
facilities are a competitive strength in a market where the price of electricity
is
-55-
increasingly determined by the cost of natural gas. Increases in the cost of
natural gas generally mean lower profit margins for energy merchants that are
dependent on natural gas-fired generation and/or higher electricity prices. In
contrast, we are dependent on coal-fired generation. To date, changes in the
cost of natural gas have not impacted on coal prices or the production of power
by coal-fired facilities.
REGIONAL MARKET STRUCTURES
North America is divided for administrative and energy transmission
purposes into ten geographic areas commonly referred to as "reliability
councils." Constraints limit transfers between and within reliability councils.
As a result, each reliability council, or portion of a reliability council,
generally constitutes a separate market for power.
Our existing generating capacity is located in the Eastern, Midwest and
Southwest regions of the United States. We primarily sell our output in portions
of the East Central Area Reliability Region, or "ECAR", the Mid-America
Interconnected Network, the Mid-Atlantic Area Council, the Southeastern Electric
Reliability Council, or "SERC" and the Western Systems Coordinating Council, or
"WSCC." The following map shows the location and regions encompassed by the
location of the ten reliability councils as well as the location of our current
power stations, future power stations and future contractually controlled
capacity.
[Graphic Omitted]
-56-
As part of the deregulation of the electric power industry, in some
areas, the role of managing the generation and transmission of energy is being
assumed by new organizations known as independent system operators, or ISOs, and
regional transmission organizations, or RTOs, that will supervise a market-based
system for generation and, in some instances, transmission of electric power.
FERC oversees the operations of these organizations and requires ISOs and RTOs
to be independent of market participants. FERC has required each electric
utility not currently in an ISO to file a plan on how it will participate in an
RTO. In addition, FERC is encouraging transmission-owning public utilities to
form large regional RTOs covering each of the Northeastern, Southwestern,
Midwestern and Western regions of the United States.
An RTO may significantly influence the economic conditions under which
our generating assets have access to markets because an RTO's structure and
operation determines transmission rates and service conditions over a large
region. An RTO will have exclusive authority to design rates for the
transmission system under its control, exclusive operational control over a
broad transmission region, exclusive control over security and short-term
reliability, responsibility for assuring that generation needed to support
transmission services is available on a non-discriminatory basis, ultimate
responsibility for transmission planning and expansion, and responsibility for
assuring that an adequate method of monitoring the competitiveness of the
regional electricity market is in place. Generally, we anticipate that RTOs will
add liquidity and stimulate competition in regional markets. We expect that our
participation in an RTO will enhance our ability to transmit power further at a
lower cost.
EASTERN REGION
FACILITIES
EXISTING FACILITIES. Our Eastern assets, as shown in the table on page
54, are primarily the 6,230 MW of generating assets that were, for the most
part, constructed and previously owned, operated and maintained by the regulated
utility subsidiaries of Allegheny Energy prior to their transfer to us. These
transferred assets are primarily base-load, coal-fired generating facilities
that were transferred to us at a net book value of approximately $257 per KW of
capacity.
Our Eastern assets and the generating assets currently owned by
Monongahela Power have low operating costs due to the economies of scale of our
larger stations and the location of almost all of the units close to our primary
fuel source in the Appalachian coal-mining region. As of September 30, 2001, 76%
of our owned generating capacity was either coal-fired or pumped-storage hydro
capacity that usually uses coal generation for its pumping needs. Of our total
coal-fired capacity of 5,962 MW, 1,535 MW of capacity from the Harrison power
station had its coal supply delivered by conveyor system due to its location at
the mouth of a mine. Another 3,541 MW of our capacity benefits from barge
delivery of coal on major navigable rivers. The remaining coal is delivered by
rail or truck. For the first nine months of 2001, the average cost of consumed
coal was $24.43 per ton. For further information on fuel costs and operation and
maintenance costs of our coal-fired generating assets that we acquired from the
utility subsidiaries of Allegheny Energy, see "--FUEL SUPPLY" and "--PLANT
OPERATIONS".
Our Eastern assets have strong transmission ties to load centers and
competitive markets in the Eastern and Midwestern United States. 5,365 MW of our
assets are connected directly to the 500 kV extra-high voltage transmission
system. This high voltage system enables us to transmit this power economically
with lower losses over longer distances. Almost all of the rest of our Eastern
assets are connected to the 138 kV transmission system. To the east, the 500 kV
system to which our Eastern assets are connected is interconnected with the PJM
Interconnection, L.L.C. and Virginia Power. To the west, the 500 kV system is
interconnected with American Electric Power. The 138 kV system also
interconnects with Duquesne Light Company in the Pittsburgh, Pennsylvania area.
While other transmission flows and temporary equipment outages sometimes limit
available transmission capacity, the strong 500 kV system in our region together
with high voltage interconnections among neighboring transmission systems enable
us to transport our generated power economically to customers to the Midwest and
the East coast.
The region to the east of our Eastern assets has a significant amount of
natural gas- and oil-fired generating capacity owned by other parties. This
region is, therefore, an attractive market for our lower-cost coal generation.
PJM Interconnection, L.L.C. to our east has both a capacity market and a power
exchange to facilitate spot market efficiency. Both of these markets supplement
the bilateral energy sales available in the PJM market and other areas
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of the Eastern and Midwestern United States. The PJM power exchange is the
oldest and most liquid power market in the east. Allegheny Energy has agreed to
join PJM through a new contractual arrangement called PJM-West which encompasses
geographically most of our Eastern assets which we expect will become
operational in the first quarter of 2002. We believe PJM-West will integrate,
for the first time, our traditional regional markets in the East Central Area
Reliability Region and the liquid regional trading markets of the PJM market by
improving our access to these markets. We expect that PJM-West, and any future
expanded markets created in the Northeastern regions of the United States, will
enhance the value of our low-cost generation asset portfolio by expanding our
market reach with lower transmission costs.
To the west of our Eastern assets, the most liquid power market is the
Cinergy hub. The Cinergy hub does not have a power exchange, but is instead a
frequently used pricing reference point in financial contracts as well as
delivery point for sales agreements requiring physical delivery of electricity.
Our ability to transmit to this trading hub gives us broad access to
counterparties and enhances our ability to effectively hedge trading activities
and manage risks.
Our subsidiary, AGC, has a 40% ownership interest in a pump-storage
hydro facility, known as Bath County, located in the extreme western portion of
Virginia Power's franchised service area. The Bath County facility stores energy
for use principally during peak-load hours by pumping water from a lower
reservoir to an upper reservoir, using the most economic available electricity,
generally during off-peak hours. Through our 77% ownership of AGC, the Bath
County facility provides us with 739 MW of peak-period low-cost generation that
is in close proximity to the potentially lucrative, high-growth Southern U.S.
market.
Potomac Edison and West Penn have assigned to us their rights and
obligations associated with their 9% participation interest in an inter-company
power agreement with the Ohio Valley Electric Corporation, an entity formed to
supply U.S. government-owned uranium enrichment facilities with power. These
generating facilities are the Kyger Creek plant located in Portsmouth, Ohio and
the Clifty Creek plant located in Madison, Indiana. The contract with the U.S.
government and its successor private corporation for such power supply is in the
process of being legally terminated by the successor corporation. Allegheny
Energy has title to 12.5% of the stock of Ohio Valley Electric Corporation which
it plans to transfer to us upon SEC and FERC approval. After the termination of
that contract and the transfer of Allegheny Energy's interest in the Ohio Valley
Electric Corporation, and barring any other disposition arrangement agreed to by
Ohio Valley Electric Corporation's sponsors, we expect to have access to
approximately 280 MW of relatively low-cost production capability located in the
Alliance RTO.
ACQUISITIONS. Subject to SEC approval, which we expect to receive by the
end of 2001, we will own an additional 46 MW of capacity within the PJM market
once the capacity from the Hunlock Creek facility in Pennsylvania is transferred
to us. This additional capacity may be characterized as a combination of
intermediate and peaking generation. All units other than the peaking generation
unit are coal-fired generation facilities. The peaking generation unit is a
natural gas-fired facility.
We are entitled to 50% of both the intermediate and peaking generation
capacity from this facility pursuant to the terms of a joint-venture with UGI,
Corp. Our 50% entitlement in the joint venture provides us with 46 MW of
additional generating capacity in the PJM market. Production costs for
intermediate capacity at the Hunlock facility, of which our portion is 24 MW,
are higher than the base-load facilities because the Hunlock Creek facility is
an older generation coal-fired plant that pre-dates the supercritical steam
temperatures and pressures widely introduced in the industry in the early 1960s.
In contrast, the peaking unit, of which our portion is 22 MW, at the Hunlock
Creek facility is a new natural gas-fired combustion turbine installation. These
units are available for dispatch within the PJM market and experience a loading
profile commensurate with their operating costs. The power from these facilities
is also available for export from the PJM market to other markets upon
appropriate notice to PJM. They are true merchant facilities in that there are
no power off-take purchases assigned or committed to our share of them.
Coal supplies are delivered to the Hunlock Creek facility predominantly
by truck from reasonably proximate sources. The natural gas for the 44 MW
combustion turbine is purchased by UGI, Corp. for the unit as a service provided
to the joint venture.
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DEVELOPMENTS. We are constructing a 540 MW combined-cycle generating
plant in Springdale, Pennsylvania. This facility will include two gas-fired
combustion turbines and one steam turbine. We expect to complete this
construction in 2003. We are initially leasing this facility.
We have also announced plans:
o to construct two simple-cycle gas combustion turbines near
Chambersburg, Pennsylvania. The two units will have a combined
capacity of 88 MW and will be capable of operating on natural gas. We
expect to complete construction of these units by the end of 2001;
o for a joint development project through which we will obtain 44 MW of
new simple-cycle combustion turbine capacity located in Buchanan
County, Virginia; and
o to participate in a joint venture with SEF Development Ltd. to own and
develop a 79 MW barge mounted, natural gas fired combustion turbine
generating facility to be located in the Brooklyn Navy Yard, New York.
We, and SEF Development, will each have a 50% ownership interest in
the joint venture. Under the terms of the joint venture, we will also
enter into an agreement with the joint venture entity to contractually
control the entire 79 MW of generating capacity of this facility,
beginning in 2002, when it becomes operational.
PROVIDER-OF-LAST-RESORT OBLIGATIONS. Under the terms of the deregulation
plans approved in Pennsylvania for West Penn, in Maryland for Potomac Edison,
and in Ohio for Monongahela Power, West Penn, Potomac Edison and Monongahela
Power are obligated to provide electricity during a transition period to all
customers who do not choose an alternate supplier of electricity and to
customers that switch back from alternate suppliers. For West Penn, the
Pennsylvania transition period continues through December 31, 2008 for all
customers with escalating capped rates. For residential customers of Potomac
Edison in Maryland, the transition period continues through December 31, 2008.
For commercial and industrial customers of Potomac Edison in Maryland, the
transition period continues through December 31, 2004. For Monongahela Power,
the transition period for Ohio residential and small commercial customers
continues through December 31, 2005, and for all other Ohio customers through
December 31, 2003.
Pursuant to long-term power sales agreements, we provide West Penn,
Potomac Edison and Monongahela Power with the amount of electricity, up to their
provider-of-last-resort retail load, that they may demand during the
Pennsylvania, Maryland and Ohio transition periods. We expect to provide power
pursuant to similar obligations to Potomac Edison and Monongahela Power in West
Virginia as this state implements customer choice. We recently renegotiated a
power sales agreement with Potomac Edison with respect to its Virginia customers
under which we have agreed to provide it with the amount of electricity up to
its provider-of-last-resort retail load that it may demand. The transition
period for customer choice in Virginia is scheduled to begin on January 1, 2002
and run through to July 2007. A significant portion of the normal operating
capacity of our fleet of transferred generating assets is currently required to
fulfill our obligations under these power sales agreements, but we expect that
this will decrease over time. As a result, these power sales agreements provide
us with a steady revenue stream during the transition periods discussed above.
These agreements do not, however, provide us with any guaranteed level of
customer sales and also mean that we are limited in our ability to pass on to
the regulated utility subsidiaries of Allegheny Energy the risk of fuel price
increases and increased costs of environmental compliance.
Our power sales agreements with West Penn, Monongahela Power with
respect to its Ohio customers and Potomac Edison with respect to its Maryland
and Virginia customers, to provide them with an amount of electricity up to
their provider-of-last-resort retail load, have a fixed price as well as a
market-based pricing component. As the amount of generating capacity we must
deliver under these agreements decreases during the transition periods described
above, the amount of electricity that is subject to market prices escalates each
year. We expect that when the transition periods end, West Penn, Potomac Edison
and Monongahela Power with respect to its Ohio customers will pay us market
rates for the entire amount of electricity provided to them.
These power sales agreements with West Penn, Monongahela Power and
Potomac Edison cannot be terminated by us unless there is a completed hostile
takeover of Allegheny Energy.
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Until customer choice is implemented in West Virginia and a power sales
agreement is entered into, the assets transferred to us by Potomac Edison will
continue to serve the retail load for West Virginia customers of Potomac Edison.
The table below shows how the total projected provider-of-last-resort
energy requirements of West Penn, Potomac Edison with respect to its Maryland
and Virginia customers and Monongahela Power with respect to its Ohio customers
declines over time, and how our contract price to those companies increases over
time. The table does not show the projected provider-of-last-resort energy
requirements of Monongahela Power's or Potomac Edison's West Virginia customers.
There are two main reasons for the increase in price. First, the
provider-of-last-resort obligation to serve industrial customers, who have the
lowest provider-of-last-resort prices, ends before that of the other customers.
For example, the provider-of-last-resort service for Maryland industrial
customers of Potomac Edison ends after 2004. The Maryland residential
provider-of-last-resort service for Potomac Edison ends after 2008. Second, the
Pennsylvania settlement agreement for West Penn includes scheduled escalation in
the provider-of-last-resort prices.
PROJECTED PROVIDER- PROJECTED PROVIDER-
PROJECTED OF-LAST-RESORT MWH OF-LAST-RESORT
PROVIDER-OF=LAST SUBJECT TO FIXED AVERAGE FIXED
RESORT MWH (IN CONTRACT PRICE CONTRACT
YEAR MILLIONS)(1) (IN MILLIONS)(1)(2) PRICE PER MWH
---- --------------- ---------------- ---------------
2001 31.9 30.8 $29.4
2002 32.4 27.1 29.5
2003 33.2 22.0 31.2
2004 29.3 16.9 32.4
2005 23.2 13.2 31.7
2006 23.0 12.6 33.7
2007 23.3 12.0 33.7
2008(3) 23.6 11.6 35.8
--------------------
(1) This column shows the total amount of electricity in MWhs that we
expect to generate. The amount of electricity delivered to customers
will be less than this amount due to transmission losses that occur in
the delivery process.
(2) This column represents the portion of the projected
provider-of-last-resort retail load in the second column that is
subject to a fixed contract price. The amount of projected
provider-of-last-resort retail load that is subject to market prices
is the difference between the projected provider-of-last-resort retail
load in the second and third columns.
(3) Final year that provider-of-last-resort obligations apply to state
with the last ending transition period.
RETAIL. Although our wholesale market activities and our power sales
agreements with West Penn, Potomac Edison and Monongahela Power discussed above
comprise the greatest volume of our electricity output and revenues, we also
participate in state retail markets in Pennsylvania, Maryland, New Jersey and
Delaware. Additionally, we are currently licensed to supply capacity in Ohio,
Virginia, New York and the District of Columbia, and we may participate in these
and other retail markets as customer choice programs evolve.
SIGNIFICANT POWER SALES. In August 2001, we were a successful bidder to
supply Baltimore Gas & Electric Company with electricity from July 2003 through
June 2006. We are committed to supply Baltimore Gas & Electric Company with an
amount needed to fulfill 10% of its provider-of-last-resort obligations.
MARKET FRAMEWORK. The PJM market is currently the predominant
marketplace in the eastern United States. The PJM market has evolved from being
the oldest and largest of tightly-dispatched generation and load-control
entities consisting of non-affiliated utility members to its current role as a
deregulated power market facilitator and independent transmission control agent.
Through various operating bodies, PJM Interconnection, L.L.C. manages a
transmission grid and power market that satisfies on a real-time basis the
service needs of more than 50,000 MW of peak load and associated generation.
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In response to FERC Order 2000, the regulated utility subsidiaries of
Allegheny Energy negotiated with PJM to form "PJM-West" which encompasses
geographically most of our Eastern assets and the remaining assets we expect to
receive from Monongahela Power. Other power companies have expressed an interest
in participating in PJM-West. FERC gave preliminary approval to the PJM-West
proposal on July 12, 2001 on the condition that Allegheny Energy submit an
additional filing to revise its transmission rates and agrees to participate in
a FERC-sponsored mediation to encourage the formation of an RTO covering all of
the markets in the Northeastern region of the United States. We expect that
PJM-West will become operational in the first quarter of 2002, shortly after we
receive final FERC approval. The operation and dispatch of the assets in
PJM-West will benefit from real-time liquid market participation while they are
committed to the PJM pool. PJM-West units will be available for service to other
markets upon advance notice of their withdrawal, individually or in groupings,
from PJM-West duty. These units will not technically be committed to any
specific load duty other than the supply of certain ancillary services to
PJM-West. Formation of a single Northeastern RTO, if it occurs, will likely
result in a larger, more liquid, and more competitive power market.
Our contractual control of 79 MW of the barge mounted, natural gas-fired
combustion turbine generating facility, when construction has been completed and
it becomes operational, will, for the first time, give us a presence in New York
City. This facility will be interconnected to the Consolidated Edison system
within the New York ISO.
We also participate indirectly in the RTO known as Alliance through our
ownership interest in the Ohio Valley Electric Corporation, which is located
within the First Energy corridor. Alliance currently represents the nearest RTO
to the immediate west of our generation facilities and encircles our generation
facilities to the immediate south. We expect that Alliance will eventually be
incorporated into a larger Midwestern RTO that will provide access to a wide
market west of Allegheny Energy. Large amounts of transmission interface
capability exists between the Allegheny Energy transmission facilities and those
of the Alliance companies. This interface capability facilitates our
east-to-west and west-to-east export and import activities.
MIDWEST REGION
FACILITIES. In May 2001, we purchased three natural gas-fired peaking
generating facilities in the Midwestern United States from Enron, which we refer
to as the "Midwest Assets," for $1.053 billion. The Midwest Assets are:
o the 546 MW Gleason simple-cycle plant, located in Gleason, Tennessee,
approximately one-hundred miles east of Memphis, interconnected with
the Tennessee Valley Authority;
o the 508 MW Wheatland simple-cycle combustion turbine complex located
near Vincennes, Indiana, interconnected dually, but not simultaneously
by any one generator, with PSI Energy/Cinergy and Indianapolis Power &
Light; and
o the 656 MW Lincoln Energy Center simple-cycle combustion turbine plant
located near Chicago, Illinois in the Commonwealth Edison-franchised
service territory.
All of the Midwest Assets are served by sufficient transmission
capability to afford reasonable access to scheduled transmission service from
the generation site. We believe the value of the Midwest Assets is enhanced by
their location because they are able to provide ancillary service support to the
transmission systems in their areas. In the past, the Lincoln Energy Center has
been called upon for system support with greater frequency than the other
Midwest Assets. In addition, the natural gas-fired combustion turbine stations
are located on major interstate pipelines and benefit from delivery via
interconnections at pressures that do not require enhancement from on-site
compressors. While all of the units are capable of being retro-fitted as
combined cycle units, the ability to retrofit these units may be constrained by
market economics and environmental regulations.
Our acquisition of the Midwest Assets will provide us with new natural
gas-fired generating capacity in the East Central Area Reliability Region,
Mid-America Interconnected Network and the Southeastern Electric Reliability
Council. We believe the Midwest Assets will assist us in transitioning from a
regional generating company to a national energy supplier. See map on page 56
for more information.
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In January 2001, we announced plans to construct a 630 MW natural
gas-fired merchant generating facility in St. Joseph County, Indiana,
approximately 10 miles west of South Bend. We plan to begin construction of the
combustion-turbine facility in 2002 and expect to complete construction in two
stages. Initially, two 44 MW single-cycle combustion turbines will be installed,
followed by the addition of about 542 MW of combined-cycle capacity in 2005.
Upon completion in 2005, the facility will enhance our ability to sell
generation in Midwest markets. To finance the construction and the purchase of
turbines and transformers for this facility we entered into leasing arrangements
in November 2001.
MARKET FRAMEWORK. During the past few years, a number of companies that
own transmission systems in the Midwest have formed the Midwest Independent
System Operator, or Midwest ISO. FERC recently accepted a settlement agreement
that would combine the Midwest ISO and Alliance ISO, but has required these
entities, and other participants to participate in a FERC-sponsored formation of
a large Midwestern RTO. Our Midwest Assets in Illinois and Indiana are located
within service territories of companies that are either active members of the
Midwest ISO or have not yet achieved separation from that ISO. The state of flux
surrounding the Midwest ISO makes it difficult to assess the impact of its
eventual composition on our operations. We believe that we will be able to
continue to successfully access markets in the Midwest region through the
Midwest ISO, or a larger Midwestern RTO.
The Gleason, Tennessee peaking facility that we acquired as part of our
Midwest Assets resides within the TVA's service territory. Although the TVA is
sufficiently large to be a market in its own right, it belongs to the
Southeastern Electric Reliability Council and relies on that council for
adjudication of policies governing independent generator operation within its
area. Currently, no independent active real-time market clearing agent oversees
power transactions within that territory. FERC, however, is seeking the
formation of a large Southeastern RTO. The TVA service territory is a
high-growth area conducive to power sales from facilities in close proximity.
The TVA service territory also has strong transmission ties to the Entergy power
market trading hub. RTO development is scheduled for the Entergy area, and we
believe that the market access provided by an RTO will be greater than that
afforded at present.
SOUTHWEST REGION
FACILITIES. Our acquisition of the Energy Trading Business provides us
with long-term contractual control over 1,000 MW of natural gas-fired generating
capacity in Southern California. This contract gives us the contractual right to
1,000 MW of the generating capacity of 14 units at three generating stations
through 2018.
In May 2001, we entered into an agreement with Las Vegas Cogeneration
II, L.L.C. for a period of 15 years. Under this agreement we will have the
contractual right to control 222 MW of generation capacity from a natural
gas-fired, combined-cycle generating facility, currently under construction by a
third party, in Las Vegas, Nevada beginning in the third quarter of 2002.
In October 2000, we announced plans to construct a 1,080 MW natural
gas-fired generating facility in La Paz County, Arizona, approximately 75 miles
west of Phoenix. We expect to begin construction of the $540 million
combined-cycle facility in 2002. When completed in 2005, the facility will allow
us to sell generation power into Arizona, California and other states served by
the Western Systems Coordinating Council, known as WSCC.
SIGNIFICANT POWER SALES. In March 2001, we entered into a power sales
agreement with the California Department of Water Resources. Under this
agreement, we have committed to supply the State of California with electricity
through December 2011. Deliveries of power have begun, with contract volumes
varying from 150 MW to 500 MW through December 2004. For the last seven years of
the agreement, the contract volume will be fixed at 1,000 MW. We plan to supply
this power primarily through our contractual right to 1,000 MW of generating
capacity in California.
MARKET FRAMEWORK. Our Arizona generation facilities and
contractually-controlled capacity in California and Nevada will be located
within the Southwest portion of the WSCC. The WSCC region encompasses
approximately 1.8 million square miles and is the largest, geographically, of
the ten regional councils of the North American Electric Reliability Council.
WSCC encompasses the states of Arizona, California, Colorado, Idaho,
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Nevada, Oregon, Utah, Washington, Wyoming and parts of Montana, New Mexico,
South Dakota and Western Canada. Much of this area may eventually be covered by
the Western RTO envisioned by FERC.
PLANT OPERATIONS
Our success depends on our ability to achieve operational efficiencies
and high availability at our generation facilities. In the new unregulated
energy industry, minimizing operating costs without compromising safety or
environmental standards, while maximizing plant flexibility and maintaining high
reliability, is critical to achieving attractive profit margins. Our operations
and maintenance practices are designed to achieve these goals. Our current
production cost is one of the lowest in the Eastern region and is one of our
significant competitive advantages. We place a high level of importance on
maximizing the operational performance and availability of our generation
assets. Our availability goals are focused on each facility's "in-market"
availability -- that is, its availability during periods when power prices are
above the variable cost of producing power at that facility.
The following table describes the operating data for the generating
assets that we acquired from West Penn, Potomac Edison and, with respect to Ohio
customers, Monongahela Power and other subsidiaries of Allegheny Energy since
1996.
TABLE OF OPERATING DATA(1)
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
2000 1999 1998 1997 1996
------------- ------------ ----------- ----------- -------------
Average availability factor 88.40% 87.87% 86.96% 89.66% 87.77%
Average capacity factor 70.52% 68.03% 67.92% 66.62% 63.09%
Net generation excluding plant use-MWh 35,953,360 34,441,778 34,750,326 34,158,126 30,980,970
Fuel per MWh-$/MWh $11.73 $11.96 $12.78 $12.93 $12.83
Operating and maintenance cost (other
than fuel) per MWh-$/MWh $3.72 $3.62 $3.50 $3.88 $4.29
- ---------------
(1) We have assumed and have included in the operating data for each period the
generation capacity as of September 30, 2001 as though we owned this
generation capacity for each year 1996 through 2000. The operating data
excludes, however, generating capacity from the Conemaugh power station and
Ohio Valley Electric Corporation, hydroelectric and oil-fired generating
capacity.
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The graph below illustrates:
o the declining operating and maintenance costs of the coal-fired
generating assets we acquired from the regulated utility subsidiaries
and other subsidiaries of Allegheny Energy since 1996. The graph
excludes operating costs for the Monongahela Power assets not yet
transferred to us, Ohio Valley Electric Corporation and the Conemaugh
generating assets; and
o that fuel represents the majority of our operating costs.
GRAPH OF OPERATING AND MAINTENANCE COSTS
Dollars/Megawatt Hours ($/Mwh)
------------------------------
Other Operating
and Maintenance
Year Fuel Cost Costs Total
---- --------- ---------------- -----
1996 $12.83 $4.29 $17.12
1997 $12.93 $3.88 $16.81
1998 $12.78 $3.50 $16.28
1999 $11.96 $3.62 $15.58
2000 $11.73 $3.72 $15.45
FUEL SUPPLY
In 2000, generating stations operated by the subsidiaries of Allegheny
Energy used approximately 18.5 million tons of coal. Of this amount
approximately seven million tons was used at generating stations equipped with
scrubbers. The use of desulfurization equipment and the cleaning and blending of
coal make burning local coal practical.
We purchased approximately 12.7 million tons of coal for use in our
operations in 2000. In 1999, 2000 and the first nine months of 2001, almost 100%
of the coal received at these stations came from mines in West Virginia,
Pennsylvania, Maryland and Ohio. Neither we nor other Allegheny Energy
subsidiaries mine or clean any coal. All raw, clean or washed coal is purchased
from suppliers as necessary to meet station requirements. We purchase coal from
a limited number of suppliers. In 2000, we purchased approximately 60% of our
fuel, primarily coal, from one supplier. In 2000, we and the utility
subsidiaries of Allegheny Energy entered into or continued long-term
arrangements with terms of one year or longer to purchase approximately 16.5
million tons of coal, or 90% of our base requirements for 2000. To the extent we
require additional amounts of coal, we use short-term arrangements and spot
purchases.
For each of the years 1995 through 1998, the average cost per ton of
coal burned at stations operated by the regulated utility subsidiaries of
Allegheny Energy was $32.68, $32.25, $32.66 and $32.26, respectively. For 1999
and 2000, the cost per ton decreased to $30.18 and $26.73 respectively. This
decrease was due to a number of factors, the most important of which were
reduced prices under two long-term contracts phased in as a result of prior
renegotiations and continued low spot-market prices. For the first nine months
of 2001, the average cost of consumed coal was $24.43 per ton.
The addition to our generating assets of natural gas-fired generation,
both through acquisitions and construction, will diversify our fuel mix from the
current predominantly coal-fired generation facilities. We believe that this
change in fuel mix and diversification will assist us in reducing our business
risks. Allegheny Energy
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Global Markets' experience in natural gas transactions will help reduce these
business risks by securing fuel supplies for our natural gas-fired generation
assets and natural gas capacity expansion.
The following table describes our projected generation capacity by fuel
type through 2005. These projections assume that our announced construction and
development projects are completed on time and that no new projects are added.
They also assume the transfer to us by Monongahela Power of its 2,111 MW West
Virginia jurisdictional assets in 2003.
PROJECTED GENERATION CAPACITY BY FUEL TYPE
FUEL TYPE
AS OF YEAR ENDED --------------------------------------------------------------------------------
DECEMBER 31, COAL OIL NATURAL GAS HYDRO TOTAL
- -------------------- ----------- ------------ ------------- ---------- ---------
2001 5,962 MW 154 MW 2,974 MW 794 MW 9,884 MW
2002 5,986 154 3,341 797 10,278
2003 7,876 154 3,969 1,034 13,033
2004 7,876 154 3,969 1,050 13,049
2005 7,876 154 5,591 1,066 14,687
- ----------------------------------------------------------------------------------------------------------
TRADING, MARKETING AND RISK MANAGEMENT OPERATIONS
Our energy trading, fuel procurement, power marketing and risk
management operations complement our power generation operations by optimizing
the return on our portfolio of generation assets. We believe that our
acquisition of the Energy Trading Business has also enhanced our risk management
skills. Generally, we seek to sell a portion of the capacity of our facilities
under fixed-price purchase contracts, fixed-capacity payments or contracts to
purchase generation at a predetermined multiple of either gas or oil prices.
This provides us with certainty as to a portion of our revenues while allowing
us to maintain flexibility with respect to the remainder of our generation
output. We evaluate the regional forward power market versus our own fundamental
analysis of projected future prices in the region to determine the amount of our
capacity we would like to sell and the terms under which we would like to sell
it pursuant to longer-term contracts. We also take operational constraints and
operating risk into consideration in making this determination. Generally, we
seek to hedge a portion of our fuel costs, which are usually linked to our power
sales. We also market energy-related commodities and offer physical and
financial wholesale energy marketing and price risk management products and
services to a variety of customers. These customers include electric utilities,
municipalities, cooperatives, power generators, marketers, or other retail
energy providers, aggregators and large volume industrial customers.
We also trade air emission allowances and credits. Because we use coal
as a fuel source, we are a significant consumer of these allowances and credits
and have a significant inventory of them. We carefully allocate these credits
and allowances for the future benefit of our operations. We take financial
positions in viable trading markets for these commodities and attempt to derive
optimum financial benefit from our inventory through such activities.
ENERGY TRADING BUSINESS
In March 2001, we acquired the Energy Trading Business from Merrill
Lynch for $489.2 million and a 1.967% equity interest in our company. The
purchase agreement includes support infrastructure that has been integrated with
our previously existing trading business. Furthermore, the purchase agreement
for the Energy Trading Business provides that if Monongahela Power's West
Virginia jurisdictional assets have not been transferred to us by September 2002
or Allegheny Energy has not completed the initial public offering of our
proposed new parent holding company's common stock by March 2003, Merrill Lynch
has the right to require Allegheny Energy to repurchase all of Merrill Lynch's
equity interest in us for $115 million plus interest calculated from March 16,
2001. We have executed employment contracts with the Energy Trading Business'
existing management team. Merrill Lynch has also entered into a non-compete
agreement expiring in September 2003 for North America. In addition, Merrill
Lynch has agreed to refer its clients with energy trading needs to us.
The Energy Trading Business is an established energy commodity trading
presence, possessing top-tier trading and marketing skills. As part of Merrill
Lynch, the Energy Trading Business was a leader among investment banks in power
trading. The Energy Trading Business has an established risk management
infrastructure, including
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risk analytics, risk reporting, option valuation and built-in redundancies. The
Allegheny Energy Global Markets' trading activities include:
o fuel tolling agreements throughout the United States, including a
long-term contractual arrangement in the Western Systems Coordinating
Council;
o load service and load-shaped arrangements in Pennsylvania, New Jersey,
Maryland, New York and the Western Systems Coordinating Council;
o asset optimization transactions;
o natural gas and crude oil transactions; and
o other derivative, structured finance and commodity risk management
strategies.
Allegheny Energy Global Markets' two-tier strategy is to focus on longer-term
transactions with higher margins and capitalize on market intelligence to create
a steady flow of short-term commodity trades.
We believe that Allegheny Energy Global Markets has a competitive
advantage to realize significant value from our generation portfolio stemming
from the Energy Trading Business:
o market information and trading experience;
o risk management infrastructure;
o derivative pricing/valuation models;
o innovative structured transaction expertise; and
o significant synergies within its existing portfolio.
We believe that our acquisition of the Energy Trading Business will
enable us to leverage a national business from which we can sell our wholesale
energy generation, allowing us to grow as a competitive energy trading merchant.
We expect our acquisition of the Energy Trading Business to result in increased
revenue and costs savings and the development of new transactions. We believe
that Allegheny Energy Global Markets will enhance our abilities to offer broader
energy risk-management, customized energy management solutions and advisory
services to customers and accelerate revenue potential from both in-house
marketing activities and the referral agreement with Merrill Lynch.
In addition, we believe that Allegheny Energy Global Markets will
greatly enhance the value of our existing generation assets and our capacity
expansion. Because the demand for, and market price of, electricity cannot be
accurately predicted, it is essential to have sophisticated energy trading and
risk management capability to maximize the value of our generating fleet and to
mitigate the risks inherent in volatile markets. Allegheny Energy Global
Markets' experience in natural gas transactions will also be valuable to us in
securing fuel supplies for our natural gas-fired generation assets and natural
gas capacity expansion. In addition, we plan to capitalize upon Allegheny Energy
Global Markets' market experience in identifying attractive opportunities for
expanding generating capacity through construction or acquisitions or
sophisticated contractual agreements.
DERIVATIVES
We use derivative financial instruments to manage and hedge our
fixed-price purchase and sale commitments and to provide fixed-price or
floating-price commitments as a service to our customers and suppliers. We also
use derivative financial instruments to reduce our exposure to the volatility of
cash market prices and to protect our investment in storage inventories.
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RISK MANAGEMENT CONTROLS
Our risk management policy establishes:
o an overall risk management framework, including periodic reviews
of our policies;
o organizational roles and responsibilities supporting segregated
duties;
o risk limits based on market, credit and non-commodity risks;
o risk measurement models and methodologies; and
o risk management reporting standards.
The Audit Committee of Allegheny Energy assists our Board of Directors
in fulfilling its oversight responsibilities related to the financial reporting
process of Allegheny Energy Global Markets' energy trading business. The Senior
Risk Officer of the Corporate Energy Risk Management Group reports directly to
the Chief Financial Officer.
COMPETITION
All of our businesses are highly competitive. Competitive pressures have
resulted from technological advances in power generation, deregulation and the
increased efficiency of energy markets. Further, we believe that as deregulation
of the energy industry continues on both the federal and state level and retail
energy markets are opened to new participants and new services, competition will
continue to be intense. In addition, the FERC's efforts to create large regional
RTOs in each of the Northeastern, Southwestern, Midwestern and Western regions
of the United States may further increase competitive pressures. During this
transition of the energy industry to competitive markets, it is difficult to
assess our position versus the position of existing power providers and new
market entrants.
With respect to power generation, we face competition in the development
and operation of energy-producing projects. Our competitors include regulated
utilities, industrial companies, non-utility generators and unregulated
subsidiaries of regulated utilities. 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. We
also face significant competition from a number of well-capitalized participants
in the non-utility power generation industry for the acquisition of non-rate
regulated power projects.
As pricing information becomes increasingly available in the energy
trading and power marketing business and as deregulation in the electricity
markets continues to accelerate, we anticipate that our energy trading, fuel
procurement, power marketing and risk management operations will experience
greater competition. Our energy trading, fuel procurement, power marketing and
risk management operations compete with other energy merchants based primarily
on the ability to aggregate supplies at competitive prices from different
sources and locations and to efficiently use 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, these operations compete against
other energy marketers on the basis of their 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
We are subject to complex and stringent energy, environmental and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of our electric
generation facilities.
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FEDERAL ENERGY REGULATORY COMMISSION
The FERC is an independent agency within the Department of Energy that
regulates the transmission and wholesale sale of electricity in interstate
commerce under the authority of the Federal Power Act. The FERC is also
responsible for authorizing exempt wholesale generators and licensing and
inspecting private, municipal and state-owned hydroelectric projects.
FEDERAL POWER ACT. The Federal Power Act gives FERC exclusive
rate-making jurisdiction over wholesale sales of electricity and transmission of
electricity in interstate commerce. FERC regulates the owners of facilities used
for the wholesale sale of electricity and its transmission in interstate
commerce as "public utilities" under the Federal Power Act. The Federal Power
Act also gives FERC jurisdiction to review certain transactions and other
activities of public utilities. Under the Federal Power Act, an entity that
sells electricity at wholesale is a public utility, subject to FERC's
jurisdiction. Because we are selling electricity in the wholesale market, we are
deemed to be a public utility for purposes of the Federal Power Act, and are
required to obtain the FERC's acceptance of our rate schedules for wholesale
sales of electricity. Generally, FERC orders that grant us market-based rate
authority reserve the right to revoke our market-based rate authority on a
prospective basis if FERC subsequently determines that we possess excessive
market power. However, in most cases, FERC does not actively regulate the rates
for facilities operated by wholesale generating companies like us.
FERC ORDER 888. In April 1996, FERC issued Order 888 requiring owners of
FERC-jurisdictional transmission facilities to provide open access to
transmission facilities with rates, terms and conditions that are materially
comparable to those that the owner imposes on itself. Order 888 was intended to
open the FERC-jurisdictional transmission grid in the continental United States
to all persons seeking transmission services.
FERC ORDER 2000. In December 1999, FERC issued Order 2000 which
encourages the voluntary restructuring of transmission operations through the
use of ISOs and RTOs. The result of establishing these entities is to eliminate
or reduce transmission charges imposed by successive transmission systems when
wholesale generators cross several transmission systems to deliver capacity.
FERC also regulates the rates, terms and conditions for electricity transmission
in interstate commerce. Tariffs established under the FERC regulation give us
access to transmission lines that enable us to sell the energy we produce into
competitive markets for wholesale energy.
FERC NORTHEAST RTO ORDER. On July 12, 2001, the FERC preliminarily
approved the application filed by the PJM Interconnection, L.L.C. and Allegheny
Energy's regulated utility subsidiaries to join the PJM market through an
arrangement called PJM-West. Among the relevant provisions of FERC's order was a
requirement that the Allegheny Energy companies, and PJM Interconnection,
L.L.C., participate in a FERC-sponsored mediation under the guidance of an
administrative law judge to encourage the formation of a single RTO covering the
Northeastern region of the United States. The initial phase of the mediation
concluded on September 17, 2001 with the submission of the business plan
developed by the diverse group of mediation participants and the administrative
law judge to FERC for approval. The business plan outlines a comprehensive
process for the development and implementation of fully-integrated markets
throughout the Northeastern region of the United States, as well as a single RTO
to administer those markets and to promote development of new infrastructure.
The business plan contemplates full operation of a single Northeastern market
between the fourth quarter of 2003 and the fourth quarter of 2004. The PJM
market model is the platform for the Northeastern RTO market, but the PJM model
will have to be modified to accommodate certain "best practices" currently used
in markets administered by the New York Independent System Operator, Inc. and
ISO New England, Inc. These "best practices" are not yet fully defined. In
addition, governance of the Northeast RTO has not yet been determined.
Accordingly, we are unable to determine the impact formation of the Northeast
RTO may have on our results of operations and business strategy.
PUBLIC UTILITY HOLDING COMPANY ACT. The Public Utility Holding Company
Act, or PUHCA, provides that any entity that owns, controls or has the power to
vote 10% or more of the outstanding voting securities of an "electric utility
company," or a holding company for an electric utility company, is subject to
regulation under PUHCA.
We are currently subject to regulation under PUHCA, as a majority-owned
subsidiary of Allegheny Energy, a registered public utility holding company.
Because we are a subsidiary of a holding company registered under
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PUHCA, we are subject to financial and organizational regulation, including
approval by the SEC of certain financings and transactions. Under the Energy
Policy Act of 1992, however, FERC can determine that a company engaged
exclusively in the business of owning or operating an eligible facility used for
the generation of electric energy for sale at wholesale is an "exempt wholesale
generator." An exempt wholesale generator is not subjected to portions of the
regulatory structure otherwise generally applicable to electric utilities and
their holding companies. In the case of facilities previously operated by
regulated utilities, FERC can make an exempt wholesale generator determination
only after the state utility commission finds that allowing the facility or
facilities to be eligible for exempt wholesale generator status will benefit
consumers, is in the public interest, and does not violate state law. We intend
to file for exempt wholesale generator status for each of the generating
facilities that have been transferred to or acquired by us which are not already
exempt wholesale generators. Additionally, we, along with Allegheny Energy, will
file to have facilities that have been de-certified as exempt wholesale
generators with FERC, reinstated to their exempt wholesale generator status
following an initial public offering of the common stock of our proposed new
parent holding company into which we will be merged and the distribution of
shares of common stock of that new holding company to Allegheny Energy
stockholders. After we have been spun-off from Allegheny Energy, we expect to be
an unregulated entity, no longer subject to PUHCA.
PROPOSED RESTRUCTURING LEGISLATION. Congress is considering legislation
that would require states to permit retail competition. In addition, state
utility commissions or state legislatures are considering, or have considered,
whether to open the retail electric power markets to competition. At present,
many states have adopted some version of a "customer choice" plan, which
typically allows customers to choose their electricity suppliers by a date that
is specified in the initiative. Although the legislation and regulatory
initiatives vary, common themes include the availability of market pricing,
retail customer choice and separation of generation assets from transmission,
distribution and other assets.
STATE ENERGY REGULATION
On the state level, public utility regulatory commissions are
responsible for approving rates and other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power to consumers. In addition, most state laws require
approval from the state commission before an electric utility operating in the
state may divest or transfer electric generation facilities. These laws also
give the commissions authority to regulate the financial activities of electric
utilities selling electricity to consumers in their states.
State public utility commissions have authority to promulgate
regulations for implementing some federal laws. In addition, state public
utility commissions may review the process by which a utility has entered into a
power sales agreement. States may also assert jurisdiction over the siting,
construction, and operation of our facilities, the issuance of securities and
the sale or other transfer of assets.
PENNSYLVANIA. In December 1996, Pennsylvania adopted the Electricity
Generation Customer Choice and Competition Act, a comprehensive restructuring
plan that culminated in full retail choice by January 1, 2001. In November 1998,
the Pennsylvania Public Utility Commission approved a settlement agreement
relating to the restructuring of West Penn serving retail customers in
Pennsylvania. Under the terms of the settlement, two-thirds of West Penn's
customers were permitted to choose an alternate generation supplier as of
January 2, 1999. The remaining one-third of West Penn's customers were permitted
to do so starting January 2, 2000. The settlement also allowed the transfer of
West Penn's 3,778 MW of generating assets to us in late 1999 at net book value.
Under the terms of the settlement, West Penn is a provider-of-last-resort during
the transition period to full market competition to all customers who do not
choose an alternate supplier of electricity and to customers that switch back
from alternate suppliers. We have renegotiated our long-term power sales
agreement with West Penn under which we are obligated to supply West Penn with
the amount of electricity, up to its provider-of-last-resort retail load, that
it may demand during the transition period.
MARYLAND. In December 1999, the Maryland Public Service Commission
approved a settlement agreement that allowed customer choice of generation
suppliers effective July 1, 2000, for all Maryland customers of Potomac Edison.
In June 2000, the Maryland Public Service Commission authorized Potomac Edison
to transfer the Maryland portion of its generation assets to us. As discussed
below, Allegheny Energy also obtained the necessary approvals from the Virginia
State Corporation Commission and the Public Service Commission of West Virginia
to
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transfer the Virginia and West Virginia portions of Potomac Edison's generation
assets to us in conjunction with the transfer of the Maryland portion of those
assets. In August 2000, Potomac Edison transferred 2,100 MW of its Maryland,
Virginia and West Virginia generation assets to us at net book value. Under the
terms of the settlement, Potomac Edison is a provider-of-last-resort during the
transition period to full market competition to all customers in Maryland who do
not choose an alternate supplier of electricity and to customers that switch
back from alternate suppliers. We have entered into a long-term power sales
agreement with Potomac Edison under which we are obligated to supply Potomac
Edison with the amount of electricity, up to its provider-of-last-resort retail
load, that it may demand during the transition period.
OHIO. The Ohio Electric Restructuring Act of 1999 provided for
implementation of retail competition beginning in 2001. In October 2000, the
Ohio Public Utilities Commission approved a settlement agreement to implement a
restructuring plan for Monongahela Power. This restructuring plan allowed Ohio
customers of Monongahela Power to choose their generation supplier starting
January 1, 2001. In addition, Monongahela Power was permitted to transfer,
together with its FERC jurisdictional assets, its Ohio jurisdictional generation
assets, consisting of a total of 352 MW, in June 2001. We have entered into a
long-term power sales agreement with Monongahela Power with respect to its Ohio
customers under which we are obligated to supply Monongahela Power with the
amount of electricity, up to its provider-of-last-resort retail load, that it
may demand during the transition period.
VIRGINIA. The Virginia Electric Utility Restructuring Act became
effective in July 1999. The law provides for a phase-in of customer choice
during the period 2002 to 2004. Pilot programs began during Fall 2000. The
Virginia State Corporation Commission allowed Potomac Edison to transfer certain
utility securities, certain contractual entitlements and generating assets,
excluding certain hydro facilities located in Virginia, to a non-regulated
affiliate at net book value. In July 2000, the Virginia State Corporation
Commission granted approval for the transfer. In July 2000, the Virginia State
Corporation Commission further approved a rate settlement associated with the
transfer. In August 2000, Potomac Edison transferred these Virginia generation
assets to us at net book value. We have negotiated a long-term power sales
agreement with Potomac Edison under which we are obligated to supply Potomac
Edison's Virginia customers with the amount of electricity up to its
provider-of-last-resort retail load in the period leading up to the
commencement, beginning January 1, 2002, of the transition period and continuing
through this period.
In December 2000, the Virginia State Corporation Commission issued an
order approving Potomac Edison's application to transfer its Virginia
hydroelectric assets to Green Valley Hydro, LLC at net book value. The transfer
will functionally separate Potomac Edison's Virginia hydroelectric facilities
from its distribution and transmission facilities, consistent with the
functional separation requirements of the Virginia Electric Utility
Restructuring Act. In May 2001, the SEC approved the formation of Green Valley
Hydro, LLC. Allegheny Energy is currently seeking SEC approval to transfer its
membership interest in Green Valley to the proposed new Maryland holding company
that will own 100% of us prior to the initial public offering.
WEST VIRGINIA. In March 2000, the West Virginia Legislature passed a
resolution approving, with certain modifications, an electric deregulation plan
submitted by the West Virginia Public Service Commission. The plan provides for
customer choice of a generation supplier for all customers and allows Allegheny
Energy to transfer to us the West Virginia jurisdictional generation assets of
Monongahela Power, approximately 2,111 MW. Under the resolution, the enactment
of legislation authorizing a deregulation plan cannot occur until the
Legislature enacts certain tax changes regarding the preservation of tax
revenues for state and local governments. The 2001 legislative session ended
without the enactment by the Legislature of the necessary tax changes that would
allow implementation of the deregulation plan to occur in West Virginia. Final
legislative activity regarding implementation of the deregulation plan has been
postponed for a year. As a result, Monongahela Power has to date not been able
to transfer its West Virginia generating assets to us. We are exploring other
ways to complete the transfer to us of Monongahela Power's West Virginia assets.
The June 2000 order by the West Virginia Public Service Commission permits
Monongahela Power to submit a petition to the West Virginia Public Service
Commission seeking approval to transfer its West Virginia generating assets
prior to the implementation of the deregulation plan. In August 2000, with a
supplemental filing in October 2000, Monongahela Power filed a petition seeking
West Virginia Public Service Commission approval to transfer its West Virginia
generating assets to us prior to the implementation of the deregulation plan.
The West Virginia Public Service Commission has not yet acted on the request.
After reaching a settlement with the West Virginia Public Service Commission or
receiving
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authorization from the West Virginia Legislature and the SEC releasing
jurisdiction over the West Virginia generating assets, Monongahela Power intends
to transfer the generation assets to us as soon as possible. If we complete a
transfer of Monongahela Power's West Virginia jurisdictional generating assets
to us, we expect to provide electricity pursuant to a long-term power sales
agreement with Monongahela Power in West Virginia during the transition period
to full market competition.
RETAIL SUPPLY IN ADJOINING STATES. We are a licensed retail supplier in
Pennsylvania, Delaware, New Jersey, New York, Maryland, Ohio, Virginia and the
District of Columbia.
ENVIRONMENTAL MATTERS
Our operations are subject to extensive federal, state and local laws
and regulations relating to air quality, water quality, waste management,
natural resources and health and safety. These laws and regulations often
require a lengthy and complex process of obtaining and renewing licenses,
permits and approvals from federal, state, and local agencies. If these laws and
regulations are changed, modifications to our facilities may be required.
AIR STANDARDS
We currently meet applicable standards as to particle emissions at our
power stations through high-efficiency electrostatic precipitators, cleaned
coal, flue-gas conditioning and, at times, reduction of output. From time to
time, we experience minor incidences of stack emission opacity that are normal
to fossil fuel operations and permitted by the regulatory process. We meet
current emission standards as to sulfur dioxide, or SO2, by the use of
scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower
the sulfur content and the blending of low-sulfur with higher-sulfur coal.
CLEAN AIR ACT AMENDMENTS OF 1990. The Clean Air Act Amendments of 1990
require, among other things, that the utility industry reduce its emissions of
SO(2) and nitrogen oxides, or NO(x). To meet the required SO(2) emission
reductions through 1999, we installed scrubbers at the Harrison power station.
We are also evaluating cost-effective options to comply with the Clean Air Act
Amendments beyond 2005, including those available in connection with the
emission allowance trading market explained below. We expect that burner
modifications at most of the stations operated by us will satisfy the NO(x)
emission reduction requirements for the acid rain provisions of the Clean Air
Act Amendments. Maryland, Pennsylvania and West Virginia are mandating
additional NO(x) reductions for ozone nonattainment reasons. These additional
reductions will require selective catalytic reduction or post-combustion
control technologies. We have installed continuous emission monitoring equipment
on units affected by the Clean Air Act Amendments.
In an effort to introduce market forces into pollution control, the
Clean Air Act Amendments created SO(2) emission allowances. An allowance is an
authorization to emit one ton of SO(2) into the atmosphere. Subject to
regulatory limitations, allowances, including bonus and extension allowances,
may be sold or banked for future use or sale. Our ownership of these allowances
permits us to operate in compliance with the present requirements of the Clean
Air Act Amendments and, as noted above, is expected to facilitate our compliance
with the future requirements of the Clean Air Act Amendments. As part of our
compliance strategy, we are studying the market for sales or purchases of
allowances and participation in certain derivative or hedging allowance
transactions.
Clean Air Act Amendments established an Ozone Transport Region
consisting of the District of Columbia, the northern part of Virginia, and 11
northeastern states, including Maryland and Pennsylvania. Sources within the
Ozone Transport Region will be required to reduce NO(x) emissions, a precursor
of ozone, to a level conducive to attainment of the one-hour Ozone National
Ambient Air Quality Standard. We have installed reasonably available control
technology consisting of overfire air equipment and/or low NO(x) burners at all
our Pennsylvania and Maryland stations. The installation of reasonably available
control technology also satisfies Clean Air Act Amendments NO(x) reduction
requirements.
Clean Air Act Amendments also established an Ozone Transport Commission.
The Ozone Transport Commission has determined that utilities within the Ozone
Transport Region will be required to make additional NO(x) reductions beyond
reasonably available control technology in order for the Ozone Transport Region
to meet the
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Ozone National Ambient Air Quality Standard. Reasonably available control
technology currently installed in Allegheny Energy's Maryland and Pennsylvania
generating plants allowed us to meet this compliance goal, and we expect to
maintain the reduction requirements through the year 2002. Further reductions
may be required. However, these reductions will most likely be superseded by the
Environmental Protection Agency's NO(x) State Implementation Plan call
regulation as discussed below.
ENVIRONMENTAL PROTECTION AGENCY REGULATION. In October 1998, the EPA
issued a NO(x) SIP call rule that required the equivalent of a uniform 0.15
lb/mmBtu emission rate throughout a 22-state region, including Maryland,
Pennsylvania, and West Virginia, beginning May 2003. The EPA's NO(x) SIP call
regulation has been subject to extensive litigation but resulted in the optional
postponement of the initial compliance date of the NO(x) SIP call from May 2003
to May 2004. During 2000, Pennsylvania and Maryland promulgated final rules to
implement the EPA's NO(x) SIP call requirements beginning May 2003. In June
2001, West Virginia issued a proposed rule to implement the EPA's NO(x) SIP call
requirements beginning May 2004. Our compliance with these stringent regulations
will require the installation of expensive post-combustion control technologies
on most of its power stations. During the period 2002 through 2004, we expect to
spend approximately $162.3 million in connection with the installation of
emission control equipment at our facilities. This amount does not include
expenditures relating to the remaining generating assets that we expect to have
transferred to us from Monongahela Power. The expected expenditures for the
installation of emission control equipment at these Monongahela Power facilities
would be $64.2 million for the same period.
In August 1997, eight northeastern states filed Section 126 petitions
with the EPA requesting the immediate imposition of up to an 85% NO(x) reduction
from utilities located in the Midwest and Southeast, including West Virginia.
The petitions claim NO(x) emissions from these upwind sources prevent attainment
by these states of the ozone standard. The Section 126 petitions have also been
subject to litigation but have now been upheld by the District of Columbia
Circuit Court of Appeals. In August 2001, the Court issued an order that
suspends the Section 126 petition rule May 1, 2003 compliance date pending EPA
review of growth factors used to calculate the state No(x) budgets.
Allegheny Energy's compliance plan for the Section 126 petition rulemaking would
be the same as the NO(x) SIP call compliance plan discussed above.
The EPA is required by law to regularly review the National Ambient Air
Quality Standards for certain pollutants including ozone, particulates, SO(2)
and NO(x). Previous litigation by the American Lung Association has expedited
these reviews. Revisions by the EPA to the SO(2) and NO(x) standards is still
the subject of litigation. A decision is not expected until early 2002. Also, in
May 1999, the EPA promulgated final regional haze regulations to improve
visibility in Class I federal areas, which includes national parks and
wilderness areas. The EPA regional haze regulation is also under litigation. If
eventually upheld in court, subsequent state regulations could require
additional reduction of SO(2) and/or NO(x) emissions from our facilities. The
effect on Allegheny Energy of revision to any of these standards or regulations
is unknown at this time, but could be substantial.
The EPA also administers Section 114 of the Clean Air Act to determine
compliance with, among other things, the federal new source performance
standards. New source performance standards can require the installation of
additional air pollution control equipment upon the major modification of an
existing facility. In August 2000, Allegheny Energy received a letter from the
EPA requiring it to provide certain information in connection with Section 114
concerning generating stations that are now owned by us and Monongahela Power.
We believe our generating facilities have been operating in accordance with the
Clean Air Act and its implementing rules. At issue is whether certain actions at
our generating facilities constitute routine maintenance that would not trigger
the requirements of the new source performance standards, or a major
modification of the facilities that would require compliance with these
standards. If the EPA decides that the new source performance standards should
be applied to our generating stations, our compliance would require significant
expenditures and we may incur significant fines. See also "-- LEGAL PROCEEDINGS
- -- ENVIRONMENTAL PROTECTION AGENCY REQUEST FOR INFORMATION" for more
information.
The final outcome of the revised ambient standards State Implementation
Plan calls, petitions filed with the EPA, and the applicability of new source
performance standards cannot be determined at this time.
In December 2000, the EPA issued a decision to regulate coal- and
oil-fired electric utility mercury emissions under Title III, Section 12 of the
Clean Air Act Amendments. The EPA plans to issue a proposed regulation by
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December 2003 and a final regulation by December 2004. The timing and level of
required mercury emission reductions are unknown at this time.
WATER STANDARDS
Under the National Pollutant Discharge Elimination System, permits for
all our stations and disposal sites are in place, and all facilities are in
compliance with permit terms, conditions and effluent limitations. However, as
permits are renewed more stringent permit limitations are being applied. Thus
far, we have successfully developed alternate site-specific water quality
criteria that are scientifically satisfactory to the regulatory agencies, and
have thus avoided incurring the costs of advanced wastewater treatment.
There is significant activity at the federal level on Clean Water Act
issues. Rulemakings are pending, for example, regarding the total maximum daily
load program, water quality standards, antidegradation review, human health and
aquatic life water quality criteria and mixing zones. In addition, the EPA is
developing new policies concerning protection of endangered species under the
Clean Water Act and imposition of new Clean Water Act requirements to address
sediment contamination. The outcome of these rulemakings may fundamentally
change the traditional water quality management program from a chemical-specific
control of point sources to comprehensive and integrated watershed management.
Over the past several years, total maximum daily loads have become a
significant issue because of successful legal challenges to the EPA's treatment
of total maximum daily loads under the Clean Water Act in various states.
Resulting consent orders in West Virginia and Pennsylvania require development
and implementation of waste loads for point sources and load allocations for
nonpoint sources on numerous water bodies not currently meeting water quality
standards within a relatively short time frame of twelve years. The direct
result of total maximum daily loads will likely be further reductions in the
amount of pollutants permitted to be discharged by our power stations located
on water quality impaired rivers. In July 2001, the EPA announced that it would
consider an 18 month review of the total maximum daily load program promulgated
before the Clinton Administration left office. The review is anticipated to
yield a more favorable rule in early 2003. We are proactively working with
interested parties to ensure development of sound and equitable total maximum
daily loads.
HAZARDOUS AND SOLID WASTES
Pursuant to the Resource Conservation and Recovery Act of 1976 and the
Hazardous and Solid Waste Management Amendments of 1984, the EPA regulates the
disposal of hazardous and solid waste materials. Maryland, Ohio, Pennsylvania,
Virginia and West Virginia have also enacted hazardous and solid waste
management regulations that are as stringent or more stringent than the
corresponding EPA regulations.
We are in a continual process of either obtaining or renewing permits
for disposal of hazardous and solid waste materials to meet future disposal
needs. All disposal areas are currently operated to be in compliance with their
permits.
In addition to using coal combustion by-products in various power plant
applications such as scrubber by-product stabilization at the Harrison and
Mitchell power stations, we continue to expand our efforts to market coal
combustion by-products for beneficial applications and thereby reduce landfill
requirements. We and the regulated utility subsidiaries of Allegheny Energy,
receive revenues from the external sale and utilization of fly ash, bottom ash
and boiler slag. In 2000, we received approximately $1,100,000 from the external
sale and utilization of approximately 435,000 tons of fly ash, 225,000 tons of
bottom ash and 28,000 tons of boiler slag. These coal combustion by-products are
beneficially used in applications such as cement replacement, anti-skid
materials, grit blasting material, mine subsidence, structural fills and
grouting of mines and oil wells.
We also constructed a processing plant that converts the flue gas
desulfurization by-product from the Pleasants power station into a commercial
grade synthetic gypsum material to be used in the manufacture of wallboard. The
processing plant supplies synthetic gypsum to a wallboard manufacturing
facility. It is expected that the plant will produce 400,000 tons of marketable
synthetic gypsum in 2001. This process will significantly reduce the amount of
by-product sent to an impoundment.
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TOXICS RELEASE INVENTORY
In 1997, the Clinton Administration announced the expansion of
right-to-know toxics release inventory reporting to include electric utilities
that use coal and/or oil for the purpose of generating power for commercial
distribution. The purpose of toxics release inventory is to provide site
specific information on chemical releases to the air, land and water.
Our operating facilities are required to complete a toxic chemical
inventory release form for each listed toxic chemical manufactured, processed,
released or otherwise used in excess of threshold levels for the applicable
reporting year. The releases reported for our facilities vary from year to year,
but are consistent with other major coal-fired generators of electricity. The
releases reported are a direct result of the volume of coal burned to meet the
demand for power. Other factors that contribute to the changes in the releases
from year to year include the kind of coal used, facility operational changes,
and revised calculation methodologies. In June 2001, Allegheny Energy reported
33 million pounds of total estimated releases for calendar year 2000.
GLOBAL CLIMATE CHANGE
Many uncertainties remain in the global climate change debate, including
the relative contributions of human activities and natural processes, the
extremely high potential costs of extensive mitigation efforts and the
significant economic and social disruptions that may result from a large-scale
reduction in the use of fossil fuels. In 2000, the Clinton Administration signed
the Kyoto Protocol, an international treaty that will require the United States
to reduce emissions of greenhouse gases by 7% from 1990 levels in the 2008-2012
time period. With normal economic growth this requirement could mean as much as
a 40% reduction of greenhouse gases by 2012. While the Bush administration has
publicly expressed opposition to the protocol, the international community is
moving forward with its ratification. The U.S. Senate has to ratify the Kyoto
Protocol before it becomes effective.
We actively participate in a number of groups to address global climate
change and help influence policy matters at the domestic and international
levels. We also conduct a program to identify cost-effective and voluntary
measures that reduce emissions of greenhouse gases in all areas of our business
and in areas such as forestry, international projects and emissions trading. We
maintain an active climate-related research program and are responsive to the
greenhouse gas guidelines suggested in the National Energy Policy Act of 1992.
We support EPRI, a nonprofit research organization for global energy suppliers,
and Edison Electric Institute's Climate Challenge Initiative, and have
committed, together with our affiliates, to invest $3 million in an
electrotechnology and a renewable energy venture capital fund.
EMPLOYEES
All officers and employees of Allegheny Supply are employed by Allegheny
Energy Service Corporation. These officers and employees, however, will become
employees of a subsidiary of our new Maryland holding company that will,
subject to SEC approval, be formed prior to the initial public offering of that
new holding company's common stock. Following the initial public offering we
expect that the number of new employees of that new holding company will
significantly increase. As of December 31, 2000, 1,502 officers and employees of
Allegheny Energy Service Corporation were dedicated to our company. Of those
employees, 329 persons were subject to collective bargaining agreements. One of
our collective bargaining agreements with our unionized employees will expire at
the end of May 2003. The other collective bargaining agreement that expired in
April 2001 has been extended and is currently operating on a day-to-day basis.
Daniel Gordon, President of Allegheny Energy Global Markets, our energy
trading business and wholly-owned subsidiary, and all current employees of this
business are employed directly by Allegheny Energy Global Markets. The employees
of the Lincoln generating facility are employees of Allegheny Energy Supply
Lincoln Generating Facility, LLC, one of our wholly-owned subsidiaries.
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PROPERTIES
Except for joint development projects, we own, in almost all cases, the
properties on which our generating facilities are built or are being
constructed.
Our corporate offices currently occupy approximately 90,000 square feet
of leased space in Monroeville, Pennsylvania pursuant to a lease agreement
expiring in 2006, with an option to extend until 2011.
In addition to our corporate office space, we lease or own various real
property and facilities relating to our projects and our construction and
development activities. Our project facilities are generally described under the
project descriptions contained elsewhere in this prospectus. We believe that we
have satisfactory title to our project facilities in accordance with standards
generally accepted in the energy industry, subject to the exceptions which, in
our opinion, would not have a material adverse effect on the use or value of the
facilities.
We believe that our existing office capacity is adequate for our needs
at least through calendar year 2005. If we require additional space, we believe
that we will be able to secure space on commercially reasonable terms without
undue disruption to our operations.
LEGAL PROCEEDINGS
We are involved in a number of judicial and regulatory proceedings,
including those described below, concerning matters arising in connection with
the conduct of our business. We believe, based on currently available
information, that the ultimate outcome of any proceedings known to us at this
time will not have a material adverse effect on our financial condition or
results of operations.
STATE OF NEW YORK AND STATE OF CONNECTICUT LITIGATION
The Attorney General of the State of New York and the Attorney General
of the State of Connecticut in 1999 notified Allegheny Energy of their intent to
commence civil actions against Allegheny Energy or certain of its subsidiaries.
The letters allege violations at the Fort Martin power station under the federal
Clean Air Act, including the new source performance standards, which require
existing power plants that make major modifications to comply with the same
emission standards applicable to new power plants.
Similar actions may be commenced by other governmental authorities in
the future. Fort Martin is a station located in West Virginia and is now jointly
owned by us and our affiliate, Monongahela Power. Both Attorneys General stated
their intent to seek injunctive relief and penalties. In addition, the Attorney
General of the State of New York in his letter indicated that he may assert
claims under the state common law of public nuisance seeking to recover, among
other things, compensation for alleged environmental damage caused in New York
by the operation of the Fort Martin power station. At this time, we are not able
to determine what effect, if any, the actions threatened by the Attorneys
General of New York and Connecticut may have on us.
ENVIRONMENTAL PROTECTION AGENCY REQUEST FOR INFORMATION
In August 2000, Allegheny Energy received a letter from the EPA
requiring it to provide certain information on the following ten electric
generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's
Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. These
electric generating stations are owned by us and Monongahela Power Company. The
letter requested information under the federal Clean Air Act to determine
compliance with federal Clean Air Act and state implementation plan
requirements, including potential application of the new source performance
standards, which can require the installation of additional air pollution
control equipment upon the major modification of an existing facility. Similar
inquiries have been made of other electric utilities and have resulted in
enforcement proceedings being brought in many cases and settlements in some of
them. We believe our generating facilities have been operated in accordance with
the Clean Air Act and the rules implementing the Clean Air Act. The experience
of other utilities, however, suggests that in recent years, the EPA may have
revised its interpretation of the rules regarding the determination of whether
an action at a facility constitutes routine maintenance that would not trigger
the requirements of the new source performance standards, or
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a major modification of the facility that would require compliance with the new
source performance standards. At this time, we are not able to determine what
effect, if any, the EPA's inquiry may have on us. If new source performance
standards are applied to our generating stations, our compliance would require
significant expenditures and we may bear substantial fines.
CLAIM BY THE UWUA TO USE PROCEEDS OF INITIAL PUBLIC OFFERING TO OFFSET RECOVERY
FROM WEST PENN CUSTOMERS OF STRANDED GENERATING COSTS
In September 2001, the Utility Workers Union of America Local 102, or
UWUA, filed a petition with the Pennsylvania Public Utility Commission. The UWUA
has requested that the Pennsylvania Public Utility Commission determine that the
initial public offering of common stock of our proposed new parent holding
company and the subsequent distribution of shares of common stock of that
holding company to Allegheny Energy stockholders be treated under the
Pennsylvania deregulation settlement order as a "sale" of the generating assets
previously transferred to us by West Penn. If the UWUA is successful in its
claim and the initial public offering and distribution constitute a sale, we
will be required to use the proceeds of the initial public offering to offset
and reduce the $670 million in stranded generating costs that West Penn is
entitled to recover from its Pennsylvania customers as a surcharge. The UWUA
contends that the initial public offering should be used to value the generating
assets transferred from West Penn and that this amount be returned to West Penn.
Although we do not believe that the UWUA petition has merit, we cannot predict
the outcome of the Pennsylvania Public Utility Commission determination or, if
the UWUA is successful in its claim, its effect on the initial public offering
and distribution.
PROCEEDINGS IN THE STATE OF CALIFORNIA AND OTHER SOUTHWESTERN STATES
On June 19, 2001, the FERC initiated proceedings to ascertain whether
and to what extent sellers of electricity in California and the other western
states may owe refunds for the period from October 1, 2000 through April 30,
2001 for possible overcharges in the sale of electricity into such markets. We
became a seller in certain southwestern markets beginning on or about March 16,
2001. In addition, Nevada Power Company or NPC filed a complaint against us with
FERC, on December 7, 2001, contending that the price in three forward sales
agreements, which were entered into by the Energy Trading Business between
December 2000 and February 2001, was excessive and should be substantially
reduced by FERC. As of September 30, 2001, the estimated fair value of the
contracts with NPC was approximately $20 million. Allegheny Energy has
intervened in the FERC refund proceedings. Based upon our information and
belief, we and Allegheny Energy believe that NPC's complaint is without merit
and that our potential liability, if any, under these proceedings is of a nature
that will not have a material adverse effect upon our financial condition.
Initial indications arising from the proceedings confirm such belief. Allegheny
Energy has also intervened in various other FERC related proceedings relating to
potential refunds and has sought rehearing of the FERC's market mitigation rules
and related court proceedings, as they would affect future markets in which we
or Allegheny Energy conduct our business and operations.
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MANAGEMENT
The following are the directors and executive officers of Allegheny
Energy Supply as of November 30, 2001:
NAME AGE POSITION
---- --- --------
Alan J. Noia 54 Chairman, Chief Executive Officer and Director
Michael Morrell 53 President, Chief Operating Officer and Director
Bruce E. Walenczyk 49 Vice President and Director
Jay Pifer 64 Director
Thomas K. Henderson 61 Vice President and Director
Richard J. Gagliardi 51 Director
Victoria V. Schaff 57 Director
David C. Benson 48 Vice President
James P. Garlick 41 Vice President
Regis F. Binder 49 Treasurer
Thomas J. Kloc 49 Controller
Daniel L. Gordon 29 President, Allegheny Energy Global Markets
Flavio C. Bartman 49 Non-Voting Director
ALAN J. NOIA, Chairman, Chief Executive Officer and Director. Since 1996,
Mr. Noia has served as the Chairman and Chief Executive Officer of Allegheny
Energy, Monongahela Power, Potomac Edison, West Penn and Allegheny Generating
Company, or AGC. Mr. Noia's other directorships include AGC (1985-1990, and
since 1994); Allegheny Energy (since 1994); Monongahela Power (since 1994);
Potomac Edison (since 1987); West Penn (since 1994); Edison Electric Institute;
Southeastern Electric Exchange; Pennsylvania Electric Association; and Ohio
Valley Electric Corporation.
MICHAEL MORRELL, President, Chief Operating Officer and Director. Mr.
Morrell was appointed our President and Chief Operating Officer on February 1,
2001. Since 1996, Mr. Morrell had served as the Chief Financial Officer and Vice
President of Allegheny Energy, Monongahela Power, Potomac Edison, West Penn and
AGC. Mr. Morrell's other directorships include Allegheny Energy, (since 1996);
Monongahela Power (since 1996), Potomac Edison (since 1996); West Penn (since
1996); and AGC (since 1996).
BRUCE E. WALENCZYK, Vice President and Director. Mr. Walenczyk was elected
Senior Vice President and Chief Financial Officer of Allegheny Energy in April
2001. He is also a Vice President and Director of Monongahela Power, Potomac
Edison and West Penn. He was Vice President - Finance of PSEG Energy Holdings
Inc. from 1998 to 2001. Prior to that he served as a Managing Director at
PaineWebber Inc. and Kidder, Peabody and Co. beginning in 1991. He had been with
Kidder, Peabody since 1983 and was primarily engaged in capital raising and
other financial advisory services for a variety of entities including electric
and gas utilities and energy companies.
JAY PIFER, Director. Mr. Pifer also serves as Senior Vice President of
Allegheny Energy (since 1996), President and Director of Monongahela Power and
Potomac Edison (since 1995) and President (since 1990) and Director (since 1992)
of West Penn.
THOMAS K. HENDERSON, Vice President and Director. Mr. Henderson also serves
as General Counsel of Allegheny Energy (since 1997) and as Vice President of
Allegheny Energy (since 1997), Monongahela Power (since 1995), Potomac Edison
(since 1995), West Penn (since 1985) and AGC (since 1996). Mr. Henderson's other
directorships include AGC (since 1996).
RICHARD J. GAGLIARDI, Director. Mr. Gagliardi has served as the Vice
President of Administration of Allegheny Energy since 1994. He was the Vice
President of Human Resources at Allegheny Energy from 1990 to 1994 and its
Director, Taxes from 1978 to 1990. From 1990 to 1996, he was the Assistant
Secretary of Monongahela Power and from 1982 to 1996, he was the Assistant
Treasurer of AGC. Mr. Gagliardi's other
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directorships include Mason-Dixon Boy Scout Council (since 1998) and Washington
County, MD Hospital (since 1997).
VICTORIA V. SCHAFF, Director. On March 1, 2001, Mrs. Schaff was appointed
to our Board of Directors effective February 1, 2001. Since 1997, Mrs. Schaff
has also served as Vice President of Allegheny Energy, and since 2000, she has
been a Vice President of West Penn, Monongahela Power and Potomac Edison. Mrs.
Schaff's other directorships include West Penn (effective February 2001),
Monongahela Power (effective February 2001) and Potomac Edison (effective
February 2001).
DAVID C. BENSON, Vice President. Mr. Benson has served as Vice President of
Allegheny Energy Service Corporation since 1996. He was also its Assistant
Treasurer from 1996 to 1998. Mr. Benson was also named Vice President of AGC in
February 2000.
JAMES P. GARLICK, Vice President. Mr. Garlick has been Vice President of
the Projects Division since January 2001. From November of 1998 until December
of 2000, he served as our director of Human Resources. From June 1998, until
November 1998, Mr. Garlick was the Regional Director of the Armstrong/Springdale
Region for West Penn and from November 1995 until June 1998, he was the Regional
Director of the R. Paul Smith/Hydro Region for Potomac Edison.
REGIS F. BINDER, Treasurer. Mr. Binder has been Treasurer since December of
1998. Mr. Binder has also served as Vice President and Treasurer of Allegheny
Energy and AGC. He is also currently Treasurer of Monongahela Power, Potomac
Edison and West Penn. From 1997 to 1998, Mr. Binder was the Executive Director
of Regulation and Rates for Allegheny Power Service Corporation and from 1996 to
1997, he was the General Manager of Industrial Marketing for Allegheny Power
Service Corporation.
THOMAS J. KLOC, Controller. Mr. Kloc has served as a Vice President and
Controller of Allegheny Energy since 1998. He is also currently the Controller
of Monongahela Power (since 1996), Potomac Edison (since 1988), West Penn (since
1995) and AGC (since 1988). Since February 1999, Mr. Kloc has been a Vice
President and Director of AGC. From 1995 to 1998, he served as the Controller of
Allegheny Power Service Corporation.
DANIEL L. GORDON, President, Allegheny Energy Global Markets. Mr. Gordon
was appointed President of Allegheny Energy Global Markets in March 2001. From
July 1998 to March 2001, he was the Head and Managing Director of Global Energy
Markets at Merrill Lynch. From June 1997 to July 1998, Mr. Gordon was a vice
president at Constellation Power Source/GS Power and prior to June 1997, he was
a vice president at the Royal Bank of Canada.
FLAVIO C. BARTMAN, Non-voting Director. Mr. Bartman was appointed pursuant
to a contract right in the Energy Trading Business purchase agreement to our
Board of Directors as a non-voting director effective June 29, 2001. Mr. Bartman
is currently Managing Director, Global Debt Markets of Merrill Lynch & Co. He
has been employed at Merrill Lynch since June 1998. Mr. Bartman also serves as a
director of MLDP Holdings, Inc.
The composition of our Board of Directors and executive officers may change
prior to the initial public offering.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
As of November 30, 2001, Allegheny Energy holds approximately 98% of our
voting securities. The remaining 2% is held by Merrill Lynch, Inc. Our parent,
Allegheny Energy, has announced its intention to effect an initial public
offering of up to 18% of the common stock of a new Maryland holding company into
which we will be merged when favorable market and other conditions exist.
Allegheny Energy plans to distribute the remaining common stock of that new
holding company and not sold in the initial public offering to stockholders of
Allegheny Energy on a tax-free basis within 24 months following completion of
the initial public offering.
The following table sets forth, as of November 30, 2001, the number of
shares of Allegheny Energy common stock that are beneficially owned, directly or
indirectly, by each director and named executive officer of our company. To the
best of our knowledge, there is no person who is a beneficial owner of more than
5% of the voting securities of Allegheny Energy.
SHARES OF PERCENTAGE
ALLEGHENY ENERGY OF
NAME COMMON STOCK CLASS (1)
- ---- ---------------- -----------
Alan J. Noia 70,830.2 *
Michael P. Morrell 23,422.9 *
David C. Benson 6,830.2 *
James P. Garlick 2,112.8 *
Thomas K. Henderson 17,861.2 *
Regis F. Binder 4,710.4 *
Thomas J. Kloc 4,782.9 *
Richard J. Gagliardi 22,358.5 *
Jay S. Pifer 30,762.4 *
Victoria V. Schaff 8,757.3 *
Bruce E. Walenczyk 1,400.0 *
All Named Executive Officers and Directors as a group (11 persons) 193,828.8 *
- --------------------
(1) "*" indicates less than 0.15% of class.
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CERTAIN TRANSACTIONS
Allegheny Energy has an approximately 98% ownership interest in us. The
following describes the material relationships and agreements that we are party
to with our parent, Allegheny Energy, and other affiliates.
RESTRUCTURING AND ASSET TRANSFERS. Pursuant to inter-company
restructuring arrangements among Allegheny Energy, its regulated utility
subsidiaries -- West Penn, Potomac Edison and Monongahela Power -- and us, the
following generating assets were transferred to us:
o In November 1999, West Penn transferred its generating assets
representing approximately 3,778 MW of capacity at a net book
value of $920.3 million. Included in this asset transfer was West
Penn's 45% ownership interest in another Allegheny Energy
subsidiary, AGC, at net book value of $71.5 million.
o In August 2000, Potomac Edison transferred its generating assets,
other than Virginia hydroelectric facilities, representing 2,100
MW of capacity, at a net book value of $446.5 million. This asset
transfer included Potomac Edison's 28% ownership interest in AGC,
at a net book value of $42.3 million, increasing our ownership
interest in AGC to 73%.
o In June 2001, Monongahela Power transferred its ownership
interest in generating assets, representing approximately 352 MW
of capacity, at a net book value of $48.8 million, allocable to
its Ohio service territory and its FERC jurisdictional
activities, including a proportionate share of its ownership in
AGC.
o In June 2001, Allegheny Energy transferred generating assets
representing 171 MW of capacity at a net book value of $125.1
million to us. This transfer included 88 MW from the AE 1 & 2
(Springdale) and 83 MW from the Conemaugh generating facilities.
In connection with the transfer of West Penn's generating assets, we
received the benefit of $7 million for the nine month period ended September 30,
2001, $9.9 million for the year ended December 31, 2000 and $3.7 million for the
year ended December 31, 1999 of competitive transition charge revenue related to
West Penn's deregulation plan.
In a similar inter-company restructuring arrangement, our goal is to
have Monongahela Power, a regulated utility subsidiary of Allegheny Energy,
transfer to us all of its remaining generating assets, representing 2,111 MW, at
a net book value to be determined.
GENERATING ASSETS LEASEBACK ARRANGEMENTS. The transfer of Potomac
Edison's generating assets to us on August 1, 2000 included Potomac Edison
assets located in West Virginia. Under a lease, a portion of these assets have
been leased back to Potomac Edison to serve its West Virginia jurisdictional
retail customers. We received rental income of $57.5 million for the nine month
period ended September 30, 2001 and $37.1 million for the year ended December
31, 2000 from this arrangement.
OPERATING AGREEMENTS. In connection with the transfer of generating
assets from West Penn, Potomac Edison and Monongahela Power to us, we entered
into operating agreements with these regulated utility subsidiaries of Allegheny
Energy. Under these agreements, the transferred generation facilities are
operated by West Penn, Potomac Edison and Monongahela Power, for our account,
pending transfer of operating permits in Pennsylvania, Maryland and Ohio. The
personnel currently operating these plants will continue to operate them after
completion of this process, and these arrangements have no financial impact.
POLLUTION CONTROL DEBT. In connection with the transfer of the
generating assets of West Penn, Potomac Edison and Monongahela Power to us, we
assumed $350.9 million of pollution control debt. As of September 30, 2001, West
Penn was a guarantor of $230.8 million, Potomac Edison was a guarantor of $104.2
million and Monongahela Power is a co-obligor of $15.9 million of this pollution
debt.
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GENERATION OUTPUT SALES. AGC sells its generation capacity to us and
Monongahela Power at rates set to recover all of its operation and maintenance
expenses, depreciation, taxes, and a return on its investment under a wholesale
rate schedule previously accepted by FERC. AGC's sales to Monongahela Power
totaled $12.6 million for the nine-month period ended September 30, 2001 and
$18.9 million for the year ended December 31, 2000.
MERCHANT CAPACITY PURCHASE. In December 1999, we purchased 276 MW of
merchant capacity at Fort Martin Unit No. 1 from an affiliate of Allegheny
Energy. In connection with this purchase, this affiliate transferred debt in the
form of a $130 million term loan to us, which has subsequently been refinanced.
TRANSMISSION SERVICES. We purchase transmission services from our
affiliates at price terms set under FERC open-access transmission tariffs.
Transmission purchases totaled $14.6 million for the nine-month period ended
September 30, 2001 and $17.8 million for the year ended December 31, 2000.
ELECTRICITY SUPPLIER TO AFFILIATES. We provide electricity to the
regulated utility subsidiaries of Allegheny Energy under fixed long-term power
sales agreements approved by FERC. These power sales agreements provide West
Penn, Potomac Edison and Monongahela Power, all of which are regulated utility
subsidiaries of Allegheny Energy, with the amount of electricity, up to their
provider-of-last-resort retail load, that they may demand throughout the
transition periods to deregulation. These power sales agreements currently
require a significant portion of the normal operating capacity of our fleet of
transferred generating assets. The rates that we charge West Penn, Potomac
Edison and Monongahela Power are set in accordance with agreements approved by
FERC. These affiliated revenues totaled $404 million for the nine-month period
ended September 30, 2001 and $678.8 million for the year ended December 31,
2000.
CAPITAL CONTRIBUTIONS AND DIVIDENDS. The total capital contributions to
us from Allegheny Energy in connection with the transfer and purchase of
generating assets were $233.8 million in 2000 and $494.3 million in 1999.
Allegheny Energy made additional capital contributions to us of $26.9 million in
2000 and $12.3 million in 1999. During 2000, we returned members' capital
contributions of $22.3 million. We also paid dividends to Allegheny Energy
totaling $67 million during 2000 and $3.4 million during 1999. Allegheny Energy
made total capital contributions to us of $445.7 million for the nine-month
period ended September 30, 2001, of which $173.9 million related to transfers of
generating assets from Allegheny Energy and Monongahela Power, and $271.8
million related to the purchase of the Midwest Assets and for other corporate
purposes.
MANAGEMENT, EMPLOYEE AND SERVICES AGREEMENTS. Allegheny Energy Service
Corporation, a subsidiary of Allegheny Energy, currently provides various
services to us, including financial and tax accounting, human resources, cash
management and treasury support, purchasing, legal, information technology
support, regulatory support, insurance brokering and office management.
Allegheny Energy Service Corporation also provides retirement, medical and life
insurance benefits to our officers, employees and their dependents. These
services are provided in accordance with the Public Utility Holding Company Act
of 1935.
In addition, other than the officers and employees of Allegheny Energy
Global Markets, our energy trading business, and Allegheny Energy Supply Lincoln
Generating Facility, LLC, all of our employees and officers are also employed by
Allegheny Energy Service Corporation. The payment of salaries, the cost of the
services provided by Allegheny Energy Service Corporation, as described in the
prior paragraph, and other general corporate expenses incurred by Allegheny
Energy Service Corporation in connection with the provision of these services to
us have been directly charged to us at cost or allocated to us using methods
that we believe are reasonable. Total billings for these services were $89.9
million for the nine months ended September 30, 2001 and $95.3 million for the
year ended December 31, 2000.
MONEY POOL. Our subsidiary, AGC, and other Allegheny Energy affiliates
use an internal money pool as a facility to accommodate intercompany short-term
borrowing needs, to the extent that these affiliates have funds available for
contribution to this pool. As of September 30, 2001, AGC had outstanding
borrowings from the money pool of $2.4 million at an interest rate of 3.08%. As
of December 31, 2000, AGC had outstanding borrowings from the money pool of
$53.2 million at an interest rate of 6.45%.
CONSOLIDATED TAX RETURN. We join with Allegheny Energy and its
subsidiaries in filing a consolidated federal income tax return. The
consolidated tax liability is allocated among the participants generally in
proportion
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to the taxable income of each participant, except that no subsidiary
pays tax in excess of its separate return tax liability. We received tax
allocation payments from Allegheny Energy of $38 million during 2000.
SHORT-TERM LOANS. Allegheny Energy and our affiliates occasionally make
short-term loans to us in order for us to meet our working capital needs.
Interest on any such loans is paid to Allegheny Energy and our affiliates at
their own short-term borrowing rate. We had no outstanding short-term borrowings
from Allegheny Energy and our affiliates at December 31, 2000. As of September
30, 2001, we had outstanding borrowings from Allegheny Energy and our affiliates
of $450.2 million. The maximum amount outstanding for the nine month period
ended September 30, 2001 was $482.4 million and $83.1 million for the year ended
December 31, 2000. Interest paid to Allegheny Energy and our affiliates on such
loans totaled $10.7 million for the nine month period ended September 30, 2001
and $1.1 million for the year ended December 31, 2000.
OTHER LEASE AGREEMENTS. We have entered into various lease arrangements
with our affiliates, primarily for office space and equipment. Total affiliated
lease rent payments of $3.4 million for the nine month period ended September
30, 2001, $3.7 million for the year ended December 31, 2000 and $0.2 million for
the year ended December 31, 1999 were recorded as rent expense.
TENANTS IN COMMON. Certain generating assets are owned jointly by us and
Monongahela Power, a regulated utility subsidiary of Allegheny Energy, as
tenants in common. The assets are operated by us and Monongahela Power, with
each of the owners being entitled to the available energy output and capacity in
proportion to its ownership in the asset. Monongahela Power performs the billing
for the jointly-owned stations located in West Virginia, while we are
responsible for billing Hatfield's Ferry Power Station, a Pennsylvania station.
In 2000, our share of the cost of the West Virginia stations was $400.3 million,
and Monongahela Power's share of the costs of Hatfield's Ferry power station was
$38.9 million. For the nine month period ended September 30, 2001 our share of
the cost of the West Virginia stations was $380.5 million, and Monongahela
Power's share of the costs at Hatfield's Ferry power station was $29.7 million.
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THE EXCHANGE OFFER
THE FOLLOWING SUMMARY OF THE REGISTRATION RIGHTS AGREEMENT AND LETTER OF
TRANSMITTAL IS NOT COMPLETE AND IS SUBJECT TO, AND IS QUALIFIED IN ITS ENTIRETY
BY, ALL OF THE PROVISIONS OF THE REGISTRATION RIGHTS AGREEMENT AND THE LETTER OF
TRANSMITTAL.
PURPOSE AND EFFECT OF EXCHANGE OFFER; REGISTRATION RIGHTS
We sold the old notes on March 9, 2001, in an unregistered private
placement to a group of investment banks that served as the initial purchasers.
The initial purchasers then resold the old notes under an offering circular
dated March 9, 2001, in reliance on Rule 144A under the Securities Act of 1933.
As a condition to the initial sale of the old notes, we and the initial
purchasers entered into a registration rights agreement. Pursuant to this
agreement, we agreed to file, at our cost, with the SEC a registration statement
under the Securities Act with regard to registered notes, called new notes, to
be exchanged for the old notes and to use our reasonable best efforts to cause
this registration statement to become effective not later than 270 days after
the date of issuance of the old notes.
The exchange offer will be open for a period of at least 30 days and not
more than 45 days (or longer if required by applicable law) after the date
notice of the exchange offer is mailed to the holders of the old notes. During
this period, we will agree to exchange the new notes for all old notes properly
surrendered and not withdrawn before the expiration date of this period.
If:
o due to any change in law or if the SEC interpretations are
changed so that they do not permit the exchange offer to take
place as planned; or
o for any other reason the exchange offer registration statement is
not declared effective by December 10, 2001 or the exchange offer
is not completed by January 24, 2002; or
o an initial purchaser makes a request on the grounds that the old
notes are not eligible to be exchanged for new notes,
we will, at our cost,
o as promptly as practicable, but in no event more than 90 days
after becoming required to do so, file a registration statement
under the Securities Act covering continuous resales of the old
notes;
o cause this registration statement, which we refer to as the
"shelf registration statement", to be declared effective; and
o use our best efforts to keep the shelf registration statement
effective until all the old notes covered by the shelf
registration statement are sold or until the old notes held by
persons that are not our affiliates become freely tradeable
pursuant to Rule 144(k) under the Securities Act, whichever
occurs first.
In the event a shelf registration statement is filed, we will provide to
each holder for whom the shelf registration was filed copies of the prospectus
which is a part of the shelf registration statement, notify each such holder
when the shelf registration statement has become effective and take other
actions as are required to permit unrestricted resales of the old notes.
A holder of the old notes that sells old notes pursuant to the shelf
registration statement generally (i) would be required to be named as a selling
security holder in the related prospectus and to deliver a prospectus to
purchasers, (ii) will be subject to applicable civil liability provisions under
the Securities Act in connection with
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sales of that kind and (iii) will be bound by the provisions of the registration
rights agreement which are applicable to that holder (including certain
indemnification obligations).
TERMS OF THE EXCHANGE OFFER
For each of the old notes properly surrendered and not withdrawn before
the expiration date of the exchange offer, a new note having a principal amount
equal to that of the surrendered old note will be issued.
The form and terms of the new notes will be the same as the form and
terms of the old notes except that:
o the new notes will be registered under the Securities Act and,
therefore, the global securities representing the new notes will
not bear legends restricting the transfer of interests in the new
notes; and
o the provisions for payment of additional interest in case of
non-registration will be eliminated.
The new notes will evidence the same indebtedness as the old notes they
replace, and will be issued under, and be entitled to the benefits of, the same
indenture that authorized the issuance of the old notes. As a result, the old
notes and the new notes will be treated as a single class of notes under the
indenture.
We intend to conduct the exchange offer in accordance with the
provisions of the registration rights agreement and the applicable requirements
of the Exchange Act and the related rules and regulations of the SEC.
Under existing SEC interpretations, the new notes would generally be
freely transferable after the exchange offer without further registration under
the Securities Act, except that broker-dealers receiving the new notes in the
exchange offer will be subject to a prospectus delivery requirement with respect
to their resale. This view is based on interpretations by the staff of the SEC
in no-action letters issued to other issuers in exchange offers like this one.
We have not, however, asked the SEC to consider this particular exchange offer
in the context of a no-action letter. Therefore, the SEC might not treat it in
the same way it has treated other exchange offers in the past. You will be
relying on the no-action letters that the SEC has issued to third parties in
circumstances that we believe are similar to ours. Based on these no-action
letters, the following conditions must be met:
o you must acquire the new notes in the ordinary course of your
business;
o you must have no arrangements or understanding with any person to
participate in the distribution of the new notes within the
meaning of the Securities Act; and
o you must not be an "affiliate" of ours, as defined in Rule 405 of
the Securities Act.
If you wish to exchange old notes for new notes in the exchange offer
you must represent to us that you satisfy all of above listed conditions. If you
do not satisfy all of the above listed conditions:
o you cannot rely on the position of the SEC set forth in the
no-action letters referred to above; and
o you must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a resale of
the new notes.
The SEC considers broker-dealers that acquired old notes directly from
us, but not as a result of market-making activities or other trading activities,
to be making a distribution of the new notes if they participate in the exchange
offer. Consequently, these broker-dealers must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with a
resale of the new notes.
A broker-dealer that has bought old notes for market-making or other
trading activities must deliver a prospectus in order to resell any new notes it
receives for its own account in the exchange offer. The SEC has taken the
position that broker-dealers may fulfill their prospectus delivery requirements
with respect to the new notes by
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delivering the prospectus contained in the registration statement for the
exchange offer. This prospectus may be used by a broker-dealer to resell any of
its new notes. We have agreed in the registration rights agreement to send a
prospectus to any broker-dealer that requests copies in the notice and
questionnaire included in the letter of transmittal accompanying the prospectus
for a period of up to 180 days after the date of expiration of this exchange
offer.
Unless you are required to do so because you are a broker-dealer or if
you do not meet the conditions described above, you may not use this prospectus
for an offer to resell, resale or other retransfer of new notes. We are not
making this exchange offer to, nor will we accept tenders for exchange from,
holders of old notes in any jurisdiction in which the exchange offer or the
acceptance of it would not be in compliance with the securities or blue sky laws
of that jurisdiction.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The expiration date for the exchange offer is 5:00 p.m., New York time,
on February , 2002. We may extend this expiration date in our sole discretion,
but in no event to a date later than , 2002. If we so extend the
expiration date, the term "expiration date" shall mean the latest date and time
to which we extend the exchange offer.
We reserve the right, in our sole discretion:
o to delay accepting any old notes;
o to extend the exchange offer;
o to terminate the exchange offer if, in our sole judgment, any of
the conditions described below under "--CONDITIONS TO THE
EXCHANGE OFFER" shall not have been satisfied; or
o to amend the terms of the exchange offer in any way we determine
is advantageous to holders of the old notes or which is not a
material change to the terms of the exchange offer.
We will give oral or written notice of any delay, extension or
termination to the exchange agent. In addition, we will give, as promptly as
practicable, oral or written notice regarding any delay in acceptance, extension
or termination of the offer to the registered holders of old notes. If we amend
the exchange offer in a manner that we determine to constitute a material
change, or if we waive a material condition, we will promptly disclose the
amendment or waiver in a manner reasonably calculated to inform the holders of
old notes of the amendment, and extend the offer if required by law.
Without limiting the manner in which we may choose to make public
announcements of any delay in acceptance, extension, termination, amendment or
waiver regarding the exchange offer, we shall have no obligation to publish,
advertise, or otherwise communicate any public announcement, other than by
making a timely release to a financial news service.
INTEREST ON THE NEW NOTES
Interest on the new notes will accrue at the rate of 7.80% per annum on
the principal amount, from the last interest payment date to which interest has
been paid on the old notes, payable semiannually in arrears on March 15 and
September 15.
On December 10, 2001, special interest will start accruing at a rate of
0.25% per annum during the 90-day period immediately following that date and
shall increase by 0.25% per annum at the end of each subsequent 90-day period
that this registration statement is not effective, but in no event shall the
rate exceed 0.50% per annum.
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CONDITIONS TO THE EXCHANGE OFFER
Despite any other term of the exchange offer, we will not be required to
accept for exchange, or exchange new notes for, any old notes, and we may
terminate the exchange offer as provided in this prospectus before the
acceptance of the old notes, if:
o the exchange offer, or the making of any exchange by a holder,
violates, in our good faith determination or on the advice of
counsel, any applicable law, rule or regulation or any applicable
interpretation of the staff of the SEC;
o any action or proceeding is instituted or threatened in any court
or by the SEC or any other governmental agency with respect to
the exchange offer which, in our judgment, would impair our
ability to proceed with the exchange offer; or
o we have not obtained any governmental approval which we, in our
sole discretion, consider necessary for the completion of the
exchange offer as contemplated by this prospectus.
The conditions listed above are for our sole benefit and we may assert
them regardless of the circumstances giving rise to any of these conditions. We
may waive these conditions in our sole discretion in whole or in part at any
time and from time to time. A failure on our part to exercise any of the above
rights shall not constitute a waiver of that right, and that right shall be
considered an ongoing right which we may assert at any time and from time to
time.
If we determine in our sole discretion that any of the events listed
above has occurred, we may, subject to applicable law:
o refuse to accept any old notes and return all tendered old notes
to the tendering holders;
o extend the exchange offer and retain all old notes tendered
before the expiration of the exchange offer, subject, however, to
the rights of holders to withdraw these old notes; or
o waive unsatisfied conditions relating to the exchange offer and
accept all properly tendered old notes which have not been
withdrawn.
Any determination by us concerning the above events will be final and
binding.
In addition, we reserve the right in our sole discretion to:
o purchase or make offers for any old notes that remain outstanding
subsequent to the expiration date; and
o 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 may differ from the terms of
the exchange offer.
PROCEDURES FOR TENDERING
Except in limited circumstances, only a DTC participant listed on a DTC
securities position listing with respect to the old notes may tender old notes
in the exchange offer. To tender old notes in the exchange offer:
o you must instruct DTC and a DTC participant by completing the
form "INSTRUCTION TO REGISTERED HOLDER FROM BENEFICIAL OWNER"
accompanying this prospectus of your intention whether or not you
wish to tender your old notes for new notes; or
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o you must comply with the guaranteed delivery procedures described
below; and
o DTC participants in turn need to follow the procedures for
book-entry transfer as set forth below under "BOOK-ENTRY
TRANSFER" and in the letter of transmittal.
By tendering, you will make the representations described below under
"REPRESENTATIONS ON TENDERING OLD NOTES." In addition, each participating
broker-dealer must acknowledge that it will deliver a prospectus in connection
with any resale of the new notes. See "PLAN OF DISTRIBUTION."
The tender by a holder of old notes will constitute an agreement between
that holder and us in accordance with the terms and subject to the conditions
set forth in this prospectus and in the letter of transmittal. If old notes are
delivered to the exchange agent by book-entry transfer, only the entire amount
of old notes held by a holder may be tendered for exchange. A holder of old
notes will be deemed to have tendered the entire amount of old notes in
connection with any book-entry transfer.
THE METHOD OF DELIVERY OF OLD NOTES, THE LETTER OF TRANSMITTAL AND ALL
OTHER REQUIRED DOCUMENTS OR TRANSMISSION OF AN AGENT'S MESSAGE, AS DESCRIBED
UNDER "BOOK-ENTRY TRANSFER," TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK
OF THE TENDERING HOLDER OF OLD NOTES. INSTEAD OF DELIVERY BY MAIL, WE RECOMMEND
THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, SUFFICIENT
TIME SHOULD BE ALLOWED TO ASSURE TIMELY DELIVERY TO THE EXCHANGE AGENT PRIOR TO
THE EXPIRATION OF THE EXCHANGE OFFER. NO LETTER OF TRANSMITTAL OR OLD NOTES
SHOULD BE SENT TO US OR DTC. DELIVERY OF DOCUMENTS TO DTC IN ACCORDANCE WITH ITS
PROCEDURES DOES NOT CONSTITUTE DELIVERY TO THE EXCHANGE AGENT.
Signatures on a letter of transmittal or a notice of withdrawal, as
described in "WITHDRAWAL OF TENDERS" below, must be guaranteed by 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, which we refer to in
this prospectus as an eligible institution, unless the old notes are tendered
for the account of an eligible institution.
We will determine in our sole discretion all questions as to the
validity, form, eligibility, including time of receipt, and acceptance and
withdrawal of tendered old notes. We reserve the absolute right to reject any
and all old notes not properly tendered or any old notes whose acceptance by us
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 any particular
old notes either before or after the expiration date. 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,
holders must cure any defects or irregularities in connection with tenders of
old notes within a period we will determine. Although we intend to request the
exchange agent to notify holders of defects or irregularities relating to
tenders of old notes, neither we, the exchange agent nor any other person will
have any duty or incur any liability for failure to give this notification. We
will not consider tenders of old notes to have been made until these defects or
irregularities have been cured or waived. The exchange agent will return any old
notes that are not properly tendered and as to which the defects or
irregularities have not been cured or waived to the tendering holders, unless
otherwise provided in the letter of transmittal, as soon as practicable
following the expiration date.
BOOK-ENTRY TRANSFER
We understand that the exchange agent will make a request promptly after
the date of this prospectus to establish accounts with respect to the old notes
at DTC for the purpose of facilitating the exchange offer. Any financial
institution that is a participant in DTC's system may make book-entry delivery
of old notes by causing DTC to transfer such old notes into the exchange agent's
DTC account in accordance with DTC's electronic Automated Tender Offer Program
procedures for such transfer. The exchange of new notes for tendered old notes
will only be made after timely:
o confirmation of book-entry transfer of the old notes into the
exchange agent's account; and
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o receipt by the exchange agent of an executed and properly
completed letter of transmittal or an "agent's message" and all
other required documents specified in the letter of transmittal.
The confirmation, letter of transmittal or agent's message and any other
required documents must be received at the exchange agent's address listed below
under "EXCHANGE AGENT" on or before 5.00 p.m., New York time, on the expiration
date of the exchange offer, or, if the guaranteed delivery procedures described
below are complied with, within the time period provided under those procedures.
As indicated above, DELIVERY OF DOCUMENTS TO DTC IN ACCORDANCE WITH ITS
PROCEDURES DOES NOT CONSTITUTE DELIVERY TO THE EXCHANGE AGENT.
The term "agent's message" means a message, transmitted by DTC and
received by the exchange agent and forming part of the confirmation of a
book-entry transfer, which states that DTC has received an express
acknowledgment from a participant in DTC tendering old notes stating:
o the aggregate principal amount of old notes which have been
tendered by the participant;
o that such participant has received an appropriate letter of
transmittal and agrees to be bound by the terms of the letter of
transmittal and the terms of the exchange offer; and
o that we may enforce such agreement against the participant.
Delivery of an agent's message will also constitute an acknowledgment
from the tendering DTC participant that the representations contained in the
letter of transmittal and described below under "REPRESENTATIONS ON TENDERING
OLD NOTES" are true and correct.
REPRESENTATIONS ON TENDERING OLD NOTES
By surrendering old notes in the exchange offer, you will be
representing that, among other things:
o you are acquiring the new notes issued in the exchange offer in
the ordinary course of your business;
o you are not participating, do not intend to participate and have
no arrangement or understanding with any person to participate,
in the distribution of the new notes issued to you in the
exchange offer;
o you are not an "affiliate", as defined in Rule 405 under the
Securities Act, of our company;
o you have full power and authority to tender, exchange, assign and
transfer the old notes tendered;
o we will acquire good, marketable and unencumbered title to the
old notes being tendered, free and clear of all security
interests, liens, restrictions, charges, encumbrances, or other
obligations relating to their sale or transfer, and not subject
to any adverse claim when the old notes are accepted by us; and
o you acknowledge and agree that if you are a broker-dealer
registered under the Exchange Act or you are participating in the
exchange offer for the purposes of distributing the new notes,
you must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary
resale of the new notes, and you cannot rely on the position of
the SEC's staff in their no-action letters.
If you are a broker-dealer and you will receive new notes for your own
account in exchange for old notes that were acquired as a result of
market-making activities or other trading activities, you will be required to
acknowledge in the letter of transmittal that you will deliver a prospectus in
connection with any resale of the new notes. The letter of transmittal states
that, by delivering a prospectus, a broker-dealer will not be deemed to be an
"underwriter" within the meaning of the Securities Act. See also "PLAN OF
DISTRIBUTION."
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GUARANTEED DELIVERY PROCEDURES
The following guaranteed delivery procedures are intended for holders
who wish to tender their old notes but:
o the holders cannot deliver the letter of transmittal or any
required documents specified in the letter of transmittal before
the expiration date of the exchange offer; or
o the holders cannot complete the procedure under the respective
DTC standard operating procedures for electronic tenders before
expiration of the exchange offer.
The conditions that must be met to tender old notes through the
guaranteed delivery procedures are as follows:
o the tender must be made through an eligible institution;
o before expiration of the exchange offer, the exchange agent must
receive from the eligible institution either a properly completed
and duly executed notice of guaranteed delivery in the form
accompanying this prospectus, by facsimile transmission, mail or
hand delivery, or a properly transmitted agent's message in lieu
of notice of guaranteed delivery:
- setting forth the name and number of the account at DTC and
the principal amount of old notes tendered;
- stating that the tender offer is being made by guaranteed
delivery; and
o guaranteeing that, within five business days after expiration of
the exchange offer, the letter of transmittal, or facsimile of
the letter of transmittal, or an agent's message and a
confirmation of a book-entry transfer of the old notes into the
exchange agent's account at DTC, and any other documents required
by the letter of transmittal will be deposited by the eligible
institution with the exchange agent; and
o the exchange agent must receive the properly completed and
executed letter of transmittal, or facsimile of the letter of
transmittal or an agent's message in the case of a book-entry
transfer, as well as a confirmation of book-entry transfer of the
old notes into the exchange agent's account, and any other
documents required by the letter of transmittal, within five
business days after expiration of the exchange offer.
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.
WITHDRAWAL OF TENDERS
Your tender of old notes pursuant to the exchange offer is irrevocable
except as otherwise provided in this section. You may withdraw tenders of old
notes at any time prior to 5:00 p.m., New York time, on the expiration date.
For a withdrawal to be effective for DTC participants, holders must
comply with their respective standard operating procedures for electronic
tenders and the exchange agent must receive an electronic notice of withdrawal
from DTC.
Any notice of withdrawal must specify the name and number of the account
at DTC to be credited with the withdrawn old notes and otherwise comply with the
procedures of the applicable facility. We will determine in our sole discretion
all questions as to the validity, form and eligibility, including time of
receipt, for such withdrawal notices, and our determination shall be final and
binding on all parties. Any old notes so withdrawn will be deemed
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not to have been validly tendered for purposes of the exchange offer and no new
notes will be issued with respect to them unless the old notes so withdrawn are
validly retendered. Any old notes which have been tendered but which are not
accepted for exchange will be returned to the holder without cost to such holder
as soon as practicable after withdrawal, rejection of tender or termination of
the exchange offer. Properly withdrawn old notes may be retendered by following
the procedures described above under "PROCEDURES FOR TENDERING" at any time
prior to the expiration date.
EXCHANGE AGENT
We have appointed Bank One Trust Company, N.A. as exchange agent in
connection with the exchange offer. Holders should direct questions, requests
for assistance and for additional copies of this prospectus, the letter of
transmittal or notices of guaranteed delivery to the exchange agent addressed as
follows:
By Mail, Hand Delivery or Overnight Courier: By Facsimile Transmission:
Bank One Trust Company, N.A. (312) 407-8853
One North State Street, 9th Floor ATTENTION: Exchanges
Chicago, Illinois 60602
ATTENTION: Exchanges CONFIRM BY TELEPHONE: (800) 524-9472
FOR INFORMATION CALL: (800) 524-9472
Delivery of a letter of transmittal to any address or facsimile number
other than the one set forth above will not constitute a valid delivery.
FEES AND EXPENSES
We will not make any payments to brokers, dealers or other persons
soliciting acceptances of the exchange offer. We will, however, pay the exchange
agent reasonable and customary fees for its services and will pay the exchange
agent for its related reasonable out-of-pocket expenses, including accounting
and legal fees. We may 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, letters of transmittal and related
documents to the beneficial owners of the old notes and in handling or
forwarding tenders for exchange.
Holders who tender their old notes for exchange will not be obligated to
pay any transfer taxes. If, however, a transfer tax is imposed for any reason
other than the exchange of old notes in connection with the exchange offer, then
the tendering holder must pay the amount of any transfer taxes due, whether
imposed on the registered holder or any other persons. If the tendering holder
does not submit satisfactory evidence of payment of these taxes or exemption
from them with the letter of transmittal, the amount of these transfer taxes
will be billed directly to the tendering holder.
CONSEQUENCES OF FAILURE TO PROPERLY TENDER OLD NOTES IN THE EXCHANGE
We will issue the new notes in exchange for old notes under the exchange
offer only after timely receipt by the exchange agent of the old notes, a
properly completed and duly executed letter of transmittal and all other
required documents. Therefore, holders of the old notes desiring to tender old
notes in exchange for new notes should allow sufficient time to ensure timely
delivery. We are under no duty to give notification of defects or irregularities
of tenders of old notes for exchange. Old notes that are not tendered or that
are tendered but not accepted by us will, following completion of the exchange
offer, continue to be subject to the existing restrictions upon transfer under
the Securities Act. Upon completion of the exchange offer, specified rights
under the registration rights agreement, including registration rights and any
right to additional interest, will be either limited or eliminated.
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Participation in the exchange offer is voluntary. In the event the
exchange offer is completed, we will not be required to register the remaining
old notes. Remaining old notes will continue to be subject to the following
restrictions on transfer:
o holders may resell old notes only if an exemption from
registration is available or, outside the U.S., to non-U.S.
persons in accordance with the requirements of Regulation S under
the Securities Act; and
o the remaining old notes will bear a legend restricting transfer
in the absence of registration or an exemption.
To the extent that old notes are tendered and accepted in connection
with the exchange offer, any trading market for remaining old notes could be
adversely affected.
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DESCRIPTION OF NOTES
GENERAL
The new notes will be issued under an indenture, dated March 15, 2001,
between us and Bank One Trust Company, N.A., as trustee. The following summaries
of certain provisions of the new notes and the indenture do not purport to be
complete and are subject, and qualified in their entirety by reference, to all
of the provisions of the new notes and the indenture, including the definitions
of terms therein.
The new notes are unsecured and will rank equally with all of our
unsecured and unsubordinated debt, if any. The new notes will be effectively
subordinated to all of our secured debt, if any.
The new notes will be denominated in U.S. dollars and principal and
interest will be paid in U.S. dollars. The new notes are not subject to any
conversion, amortization, or sinking fund.
The new notes are not guaranteed by, or otherwise obligations of,
Allegheny Energy or any of its direct or indirect subsidiaries other than our
company.
In the discussion that follows, references to paying principal of the
new notes are to payment at maturity or redemption.
Definitions of certain capitalized terms used below can be found at the
end of this section under "CERTAIN DEFINITIONS."
PRINCIPAL, MATURITY AND INTEREST
The new notes are unlimited in aggregate principal amount. The new notes
initially will be issued in an aggregate principal amount of up to $400,000,000.
The new notes will mature on March 15, 2011. Interest will be payable on
the new notes semiannually on March 15 and September 15 of each year until the
principal is paid or made available for payment. Interest on the new notes will
accrue from the most recent date to which interest has been paid or, if no
interest has been paid, from the date of issuance. Interest will be computed on
the basis of a 360-day year comprised of twelve 30-day months.
Payment of principal of the new notes will be made against surrender of
such new notes at the office or agency of our company in Hagerstown, Maryland.
Payment of interest on the new notes will be made to the person in whose name
such new notes are registered at the close of business on the March 1 or
September 1 immediately preceding the relevant interest payment date. For so
long as the new notes are issued in book-entry form, payments of principal and
interest shall be made in immediately available funds by wire transfer to The
Depository Trust Company, or DTC, or its nominee. If the new notes are issued in
certificated form to a holder other than DTC, payments of principal and interest
will be made by check mailed to such holder at such holder's registered address
or, upon written application by a holder of $1,000,000 or more in aggregate
principal amount of new notes to the trustee in accordance with the terms of the
indenture, by wire transfer of immediately available funds to an account
maintained by such holder with a bank or other financial institution. Default
interest will be paid in the same manner to holders as of a special record date
established in accordance with the indenture.
All amounts paid by us for the payment of principal, premium, if any, or
interest on any new notes that remain unclaimed at the end of two years after
such payment has become due and payable will be repaid to us and the holders of
such new notes will thereafter look only to us for payment thereof.
REDEMPTION AT OUR OPTION
We may, at our option, redeem the new notes in whole or in part at any
time at a redemption price equal to the greater of:
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o 100% of the principal amount of the new notes to be redeemed,
plus accrued interest to the redemption date, or
o as determined by the Quotation Agent, the sum of the present
values of the remaining scheduled payments of principal and
interest on the new notes to be redeemed (not including any
portion of payments of interest accrued as of the redemption
date) discounted to the redemption date on a semi-annual basis at
the Adjusted Treasury Rate plus 35 basis points, plus accrued
interest to the redemption date.
The redemption price will be calculated assuming a 360-day year
consisting of twelve 30-day months.
We will mail notice of any redemption at least 30 days but not more than
60 days before the redemption date to each holder of the new notes to be
redeemed.
Unless we default in payment of the redemption price, on and after the
redemption date, interest will cease to accrue on the new notes or portions of
the new notes called for redemption.
BOOK-ENTRY SYSTEM
Upon issuance, all new notes will be represented by a single global
note.
Each global note will be deposited with, or on behalf of The Depository
Trust Company, or DTC, and registered in the name of DTC's nominee, Cede & Co.
DTC has advised us as follows: DTC is a limited purpose trust company
organized under the laws of the State of New York, a "banking organization"
within the meaning of the New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the 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 was
created to hold securities for its participants ("participants") and to
facilitate the clearance and settlement of securities transactions, such as
transfers and pledges, among participants in deposited securities through
electronic computerized book-entry changes to accounts of its participants,
thereby eliminating the need for physical movement of securities certificates.
"Direct participants" 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, Inc.,
the American Stock Exchange, Inc. and the National Association of Securities
Dealers, Inc. Access to DTC's system is also available to others such as
securities brokers and dealers, banks and trust companies that clear 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 SEC.
Purchases of new notes under 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 purchaser of each note, each
called a 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 purchase, but beneficial owners are expected to receive
written confirmations providing details of the transactions, as well as periodic
statements of their holdings, from the direct or indirect participant through
which the beneficial owner 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 the use of the book-entry system for the new
notes is discontinued as described below.
To facilitate subsequent transfers, all new notes deposited by
participants with DTC are registered in the name of DTC's nominee, Cede & Co.
The deposit of new notes with a custodian for 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
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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.
Conveyance 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 shall be sent to Cede & Co. If less than all of the
interests in a new note are being redeemed, DTC's practice is to determine by
lot the amount of the interest of each direct participant in such new note to be
redeemed.
Neither DTC nor Cede & Co. will consent or vote with respect to the new
notes. Under its usual procedures, DTC mails an omnibus proxy to the issuer as
soon as possible after the record date. The omnibus proxy assigns Cede & Co.'s
consenting or voting rights to those direct participants to whose accounts
interests in the new notes are credited on the record date (identified in a
listing attached to the omnibus proxy).
Principal and interest payments on the new notes will be made to DTC by
wire transfer of immediately available funds. DTC's practice is to credit direct
participants' accounts on the 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 the 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 participant
and not of DTC or us, subject to any statutory or regulatory requirements as may
be in effect from time to time. Payment of principal and interest to DTC is our
responsibility, disbursement of such payments to direct participants shall be
the responsibility of DTC, and disbursement of such payments to the beneficial
owners shall be the responsibility of direct and indirect participants. Neither
we, the trustee nor any initial purchaser will have any responsibility or
liability for any aspect of the records relating to or payments made on account
of beneficial ownership interests in the global notes or for maintaining,
supervising or reviewing any records relating to such beneficial ownership
interests.
DTC may discontinue providing its services as securities depositary with
respect to the new notes at any time by giving reasonable notice to us.
New notes represented by a global note are exchangeable for certificated
notes with the same terms in authorized denominations only if:
o DTC notifies us that it is unwilling or unable to continue as
depositary for such global note or if DTC ceases to be a clearing
agency registered under applicable law and a successor depositary
is not appointed by us within 90 days;
o we determine not to require all of the new notes to be
represented by a global note and notify the trustee of our
decision; or
o there shall have occurred and be continuing an event of default
or any event which after notice or lapse of time or both would be
an event of default with respect to the notes.
CERTAIN DEFINITIONS
Set forth below are definitions of some of the terms used in this
prospectus.
"Adjusted Treasury Rate" means, with respect to any redemption date, the
rate per year equal to the semi-annual equivalent yield to maturity of the
Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue
(expressed as a percentage of its principal amount) equal to the Comparable
Treasury Price for that redemption date.
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"Business Day" means any day that is not a day on which banking
institutions in New York City are authorized or required by law or regulation to
close.
"Comparable Treasury Issue" means the United States Treasury security
selected by the Quotation Agent as having a maturity comparable to the remaining
term of the new notes that would be used, 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.
"Comparable Treasury Price" means, with respect to any redemption date:
o the average of the Reference Treasury Dealer Quotations for that
redemption date, after excluding the highest and lowest of the
Reference Treasury Dealer Quotations; or
o if the trustee obtains fewer than three Reference Treasury Dealer
Quotations, the average of all Reference Treasury Dealer
Quotations so received.
"Indebtedness" of any person means (i) all indebtedness of such person
for borrowed money, (ii) all obligations of such person evidenced by bonds,
debentures, notes or other similar instruments, (iii) all obligations of such
person to pay the deferred purchase price of property or services, (iv) all
indebtedness created or arising under any conditional sale or other title
retention agreement with respect to property acquired by such person (even
though the rights and remedies of the seller or lender under such agreement in
the event of default are limited to repossession or sale of such property), (v)
all capital lease obligations of such person (excluding leases of property in
the ordinary course of business), (vi) all obligations, contingent or otherwise,
of such person under acceptance, letter of credit or similar facilities other
than commercial leases, (vii) all unconditional obligations of such person to
purchase, redeem, retire, defease or otherwise acquire for value any capital
stock or other equity interests of such person or any warrants, rights, or
options to acquire such capital stock or other equity interests, (viii) all
Indebtedness of any other person of the type referred to in clauses (i) through
(vii) guaranteed by such person or for which such person shall otherwise
(including pursuant to any keepwell, makewell or similar arrangement) become
directly or indirectly liable, and (ix) all Indebtedness of the type referred to
in clauses (i) through (vii) above secured by (or for which the holder of such
Indebtedness has an existing right, contingent or otherwise, to be secured by)
any lien or security interest on property.
"Quotation Agent" means the Reference Treasury Dealer appointed by us.
"Rating Agencies" means Standard & Poor's Rating Services, Moody's
Investors Services, Inc. and Fitch, Inc.
"Reference Treasury Dealer" means (i) each of Salomon Smith Barney Inc.,
Banc of America Securities LLC, Chase Securities Inc., Mellon Financial Markets,
LLC and SunTrust Equitable Securities Corporation and their respective
successors, unless any of them ceases to be a primary U.S. Government securities
dealer in New York City (a "Primary Treasury Dealer"), in which case we shall
substitute another Primary Treasury Dealer; and (ii) any other Primary Treasury
Dealer selected by us.
"Reference Treasury Dealer Quotations" means, with respect to each
Reference Treasury Dealer and any redemption date, the average, as determined by
the trustee, 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 trustee by that Reference Treasury Dealer at 5:00 p.m., New York
City time, on the third business day preceding that redemption date.
"Subsidiary" means any corporation or other entity of which sufficient
voting stock or other ownership or economic interests having ordinary voting
power to elect a majority of the board of directors (or equivalent body) are at
the time directly or indirectly held by us.
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CERTAIN COVENANTS
MERGERS AND CONSOLIDATIONS
We will not consolidate with or merge with or into any other person, or
sell, convey, transfer or lease our properties and assets substantially as an
entirety to any person, and we will not permit any person to consolidate with or
merge with or into us, unless:
o immediately prior to and immediately following such
consolidation, merger, sale or lease, no Event of Default under
the indenture shall have occurred and be continuing; and
o we are the surviving or continuing corporation, or the surviving
or continuing corporation or corporation that acquires by sale,
conveyance, transfer or lease is incorporated in the United
States and expressly assumes the payment and performance of all
of our obligations under the indenture and the new notes.
LIMITATION ON LIENS
We shall not, and shall not permit any Subsidiary to issue, assume,
guarantee or permit to exist any Indebtedness secured by any lien on any
property of ours or any Subsidiary's, whether owned on the date that the new
notes are issued or thereafter acquired, without in any such case effectively
securing the outstanding new notes (together with, if we shall so determine, any
other Indebtedness of or guaranteed by our company ranking equally with the new
notes) equally and ratably with such Indebtedness (but only so long as such
Indebtedness is so secured); provided, however, that the foregoing restriction
shall not apply to the following permitted liens:
(i) pledges or deposits in the ordinary course of business in
connection with trading in electricity and other forms of energy,
as well as those related to financial or other hedging
obligations, and in connection with bids, tenders, contracts or
statutory obligations or to secure surety or performance bonds;
(ii) liens imposed by law, such as carriers', warehousemen's and
mechanics' liens, arising in the ordinary course of business;
(iii) liens for property taxes being contested in good faith;
(iv) minor encumbrances, easements or reservations which do not in the
aggregate materially adversely affect the value of the properties
or impair their use;
(v) liens on any property existing at the time of acquisition thereof
(which liens may also extend to subsequent repairs, alterations
and improvements to such property);
(vi) liens on property existing at the time of acquisition thereof by
us or a Subsidiary, or to secure any indebtedness incurred by us
or a Subsidiary prior to, at the time of, or within 270 days
after the later of the acquisition, the completion of
construction (including any improvements on an existing property)
or the commencement of commercial operation of the property,
which indebtedness is incurred for the purpose of financing all
or any part of the purchase price or construction or
improvements; PROVIDED, HOWEVER, that in the case of any such
acquisition, construction or improvement the lien shall not apply
to any property previously owned by us or a Subsidiary;
(vii) liens, if any, in existence on the date that the new notes are
issued;
(viii) mortgages securing obligations issued by a state, territory or
possession of the United States, or any political subdivision of
any of the foregoing or the District of Columbia, to finance the
acquisition or construction of property, and on which the
interest is not, in the opinion of tax counsel of recognized
standing or in accordance with a ruling issued by the Internal
Revenue Service, includible in gross income of the holder by
reason of Section 103(a)(1) of the Internal Revenue Code (or any
successor to such
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provision) as in effect at the time of the issuance of such
obligations;
(ix) other liens to secure Indebtedness so long as the amount of
outstanding Indebtedness secured by liens pursuant to this clause
(ix) does not exceed 30% of our consolidated assets; and
(x) liens granted in connection with extending, renewing, replacing
or refinancing any of the Indebtedness (so long as there is no
increase in the principal amount of the Indebtedness), described
in the foregoing clauses (v) through (ix).
In the event that we shall propose to pledge, mortgage or hypothecate
any property, other than as permitted by clauses (i) through (x) of the previous
paragraph, we shall (prior thereto) give written notice thereof to the trustee,
who shall give notice to the holders, and we shall, prior to or simultaneously
with such pledge, mortgage or hypothecation, effectively secure all the new
notes equally and ratably with such Indebtedness.
RESTRICTION ON SALES AND LEASEBACKS
We shall not, and shall not permit any Subsidiary to, enter into any
sale and leaseback transaction unless we comply with this restrictive covenant.
A "sale and leaseback transaction" generally is an arrangement between us or any
Subsidiary and a bank, insurance company or other lender or investor where we or
any Subsidiary lease real or personal property which was or will be sold by us
or any Subsidiary to that lender or investor.
We can comply with this restrictive covenant if we meet either of the
following conditions:
(i) the sale and leaseback transaction is entered into prior to,
concurrently with or within 270 days after the acquisition, the
completion of construction (including any improvements on an
existing property) or the commencement of commercial operations
of the property; or
(ii) we or our Subsidiary could otherwise grant a lien on the property
as a permitted lien described in "--Limitation on Liens."
EVENTS OF DEFAULT
"Event of default" means any of the following:
o failure to pay the principal of (or premium, if any, on) any new
note when due and payable;
o failure to pay for 30 days any interest on any new note when due
and payable;
o an event of default, as defined in any of our instruments under
which there may be issued, or by which there may be secured or
evidenced, any Indebtedness of our company that has resulted in
the acceleration of such Indebtedness, or any default occurring
in payment of any such Indebtedness at final maturity (and after
the expiration of any applicable grace periods), other than such
Indebtedness the principal of, and interest on which, does not
individually, or in the aggregate, exceed $25,000,000;
o failure to perform any other requirements in the new notes or in
the indenture for 60 days after notice;
o one or more final judgments, decrees or orders of any court,
tribunal, arbitrator, administrative or other governmental body
or similar entity for the payment of money is rendered against us
or any of our properties in an aggregate amount in excess of
$25,000,000 (excluding the amount covered by insurance) and such
judgment, decree or order remains unvacated, undischarged and
unstayed for more than 60 consecutive days, except while being
contested in good faith by appropriate proceedings; or
o certain events of bankruptcy or insolvency.
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If an event of default occurs and continues, the trustee or the holders
of at least 25% of the principal amount of the new notes may require us to repay
the entire principal of the new notes immediately ("repayment acceleration"). In
most instances, the holders of at least a majority in aggregate principal amount
of the new notes may rescind a previously triggered repayment acceleration.
However, if we cause an event of default because we have failed to pay
(unaccelerated) principal, premium, if any, or interest, repayment acceleration
may be rescinded only if we have first cured our default by depositing with the
trustee enough money to pay all (unaccelerated) past due amounts and penalties,
if any.
The trustee must within 90 days after a default occurs, notify the
holders of the new notes of default unless such default has been cured or
waived. We are required to file an annual certificate with the trustee, signed
by an officer, concerning any default by us under any provisions of the
indenture.
Subject to the provisions of the indenture relating to its duties in
case of default, the trustee shall be under no obligation to exercise any of its
rights or powers under the indenture at the request, order or direction of any
holders unless such holders offer the trustee reasonable indemnity. Subject to
the provisions for indemnification, the holders of a majority in principal
amount of the new notes of any series may direct the time, method and place of
conducting any proceedings for any remedy available to, or exercising any trust
or power conferred on, the trustee with respect to such new notes.
MODIFICATION OF INDENTURE
Under the indenture, our rights and obligations and the rights of the
holders of any new notes may be changed. Any change affecting the rights of the
holders of any series of new notes requires the consent of the holders of not
less than a majority in aggregate principal amount of the outstanding new notes
of all series affected by the change, voting as one class. However, we cannot
change the terms of payment of principal or interest, or a reduction in the
percentage required for changes or a waiver of default with respect to any new
note unless the holder consents. We may take other action that does not affect
the rights of holders by executing supplemental indentures without the consent
of any noteholders.
DEFEASANCE
We may at any time terminate all of our obligations with respect to the
new notes ("defeasance"), except for certain obligations, including those
regarding any trust established for a defeasance and obligations to register the
transfer or exchange of the new notes, to replace mutilated, destroyed, lost or
stolen new notes as required by the indenture and to maintain agencies in
respect of new notes. We may at any time terminate our obligations under certain
restrictive covenants set forth in the indenture and any omission to comply with
such obligations shall not constitute an event of default with respect to the
new notes ("covenant defeasance"). To exercise either defeasance or covenant
defeasance, we must deposit in trust, for the benefit of the holders of the new
notes, with the trustee sufficient cash or U.S. government securities, or a
combination thereof, in such amounts as will be sufficient to pay the principal
of, and premium, if any, and interest on the new notes and any other sums due to
the stated maturity date or a redemption date of the new notes and deliver to
the trustee an opinion of counsel stating that the federal income tax
obligations of noteholders will not change as a result of us performing the
action described above.
SATISFACTION AND DISCHARGE
The indenture will be discharged and will cease to be of further effect
(except as to surviving rights or registration of transfer or exchange of new
notes) as to all outstanding new notes when:
o either (a) all such new notes theretofore authenticated and
delivered (except lost, stolen or destroyed new notes that have
been replaced or paid and new notes for whose payment money has
been deposited in trust or segregated and held in trust by us and
repaid to us or discharged from such trust) have been delivered
to the trustee for cancellation or (b) all such new notes not
theretofore delivered to the trustee for cancellation have become
due and payable, will become due and payable at the stated
maturity date within one year, or are to be called for redemption
within one year under arrangements satisfactory to the trustee
for the giving of notice of redemption by the trustee in our
name, and at our
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expense, and we have deposited or caused to be deposited with the
trustee as trust funds in trust for the purpose sufficient cash
or government obligations in such amounts sufficient to pay and
discharge the entire indebtedness on the new notes not
theretofore delivered to the trustee for cancellation, for
principal amount, premium, if any, and interest to the date of
such deposit (in the case of new notes which have become due and
payable) or to the stated maturity date or a redemption date, as
the case may be;
o we have paid or caused to be paid all other sums payable by us
under the indenture; and
o we have delivered (a) irrevocable instructions to the trustee to
apply the deposited money toward the payment of the new notes at
the stated maturity or on a redemption date, as the case may be
and (b) an officers' certificate and an opinion of counsel
stating that all conditions precedent to satisfaction and
discharge have been complied with.
CONCERNING THE TRUSTEE
We and our affiliates use or will use some of the banking services of
the trustee in the normal course of business.
GOVERNING LAW
The indenture, the supplemental indentures and the new notes will be
governed by the laws of the State of New York.
RATINGS
Standard & Poor's Rating Services, Moody's Investors Service, Inc. and
Fitch, Inc. have given the new notes the ratings set forth under "SUMMARY --
TERMS OF THE NEW NOTES." Such ratings reflect only the views of these
organizations, and an explanation of the significance of each such rating may be
obtained from Standard & Poor's Rating Services, 55 Water Street, New York, New
York 10004, Moody's Investors Service, Inc., 99 Church Street, New York, New
York 10007, or Fitch, Inc., One State Street Plaza, New York, New York 10004. A
security rating is not a recommendation to buy, sell or hold securities, and
each rating should be evaluated independently of any other rating. There is no
assurance that such ratings will continue for any given period of time or that
they will not be revised downward or withdrawn entirely by such rating agencies
or either of them if, in their judgment, circumstances so warrant. A downward
change in or withdrawal of such ratings by any of them may have an adverse
effect on the market price of the new notes.
IMPORTANT FEDERAL INCOME TAX CONSIDERATIONS
The exchange of old notes for new notes will not be treated as a taxable
transaction for U.S. Federal income tax purposes because the terms of the new
notes will not be considered to differ materially in kind or extent from the
terms of the old notes. Rather, the new notes you receive will be treated as a
continuation of your investment in the old notes. As a result, you will not have
any material U.S. Federal income tax consequences if you exchange your old notes
for new notes.
IF YOU ARE THINKING ABOUT EXCHANGING YOUR OLD NOTES FOR NEW NOTES, YOU
SHOULD CONSULT YOUR OWN TAX ADVISORS CONCERNING THE TAX CONSEQUENCES ARISING
UNDER STATE, LOCAL OR FOREIGN LAWS.
EXPERTS
The financial statements of Allegheny Energy Supply Company, LLC as of
December 31, 2000 and 1999 and for the year ended December 31, 2000 and for the
period November 18, 1999 to December 31, 1999 included in this Prospectus have
been so included in reliance on the report of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
The Statement of Assets Acquired and Liabilities Assumed as of December
29, 2000 and Statement of Revenues and Direct Expenses for the year ended
December 29, 2000 of the Global Energy Markets (a unit of Merrill Lynch Capital
Services) business purchased on March 16, 2001 by Allegheny Energy Supply
Company, LLC included in this Prospectus have been so included in reliance on
the report of PricewaterhouseCoopers LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.
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PLAN OF DISTRIBUTION
Each broker-dealer that receives new notes for its own account in
connection with the exchange offer must acknowledge that it will deliver a
prospectus in connection with any resale of those new notes. A broker-dealer may
use this prospectus, as amended or supplemented from time to time, in connection
with resales of new notes received in exchange for old notes where such
broker-dealer acquired old notes as a result of market-making activities or
other trading activities. We have agreed that for a period of 180 days after the
expiration date of the exchange offer, we will make available a prospectus, as
amended or supplemented, meeting the requirements of Securities Act to any
broker-dealer for use in connection with those resales.
We will not receive any proceeds from any sale of new notes by
broker-dealers. Broker-dealers may sell new notes received by them for their own
account pursuant to the exchange offer 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 those 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 broker-dealer or
the purchasers of any 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
participates in a distribution of such new notes may be deemed to be an
"underwriter" within the meaning of the Securities Act. A 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 expiration date of the 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
these documents in the letter of transmittal. We have agreed to pay all expenses
incident to the exchange offer, including the expenses of one counsel for the
holders of the old notes other than commission or concessions of any broker or
dealers and will indemnify the holders of the old notes, including any
broker-dealers, against specified liabilities, including liabilities under the
Securities Act.
VALIDITY OF THE NOTES
The validity of the new notes will be passed upon for us by Sullivan &
Cromwell, 125 Broad Street, New York, New York 10004-2498.
AVAILABLE INFORMATION
We have filed a registration statement on Form S-4 with the SEC in
connection with this exchange offer. This prospectus is part of that
registration statement. When this registration statement goes effective, we will
be required to file annual, quarterly and current reports and other information
with the SEC. You may read and copy any documents filed by us at the SEC's
public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please
call the SEC at 1-800-SEC-0330 for further information on the public reference
room. Our filings with the SEC are also available to the public through the
SEC's Internet site at http://www.sec.gov. You may review a copy of the
registration statement at the SEC's public reference room in Washington, D.C.,
as well as through the SEC's Internet site.
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INDEX TO FINANCIAL STATEMENTS
Consolidated Statement of Operations - For the three months and nine months
ended September 30, 2001 and 2000 (Unaudited)........................................... F-2
Consolidated Statement of Cash Flows - For the nine months
ended September 30, 2001 and 2000 (Unaudited)........................................... F-3
Consolidated Balance Sheets - September 30, 2001 and
December 31, 2000 (Unaudited)........................................................... F-5
Consolidated Statement of Comprehensive Income - For the three months and nine months
ended September 30, 2001 and 2000 (Unaudited)........................................... F-7
Notes to Consolidated Financial Statements (Unaudited)....................................... F-8
Report of Independent Accountants............................................................ F-17
Consolidated Statement of Operations - For the year ended December 31, 2000
and for the Period from November 18, 1999 Inception Date through
December 31, 1999 ...................................................................... F-18
Consolidated Statement of Members' Equity - For the year ended December 31, 2000
and for the Period from November 18, 1999 Inception Date through
December 31, 1999 ...................................................................... F-19
Consolidated Statement of Cash Flows - For the year ended December 31, 2000
and for the Period from November 18, 1999 Inception Date through
December 31, 1999 ...................................................................... F-20
Consolidated Balance Sheet - December 31, 2000 and December 31, 1999......................... F-21
Notes to Consolidated Financial Statements................................................... F-23
Quarterly Financial Information - For the quarterly periods ended December 31, 1999,
March 31, 2000, June 30, 2000, September 30, 2000 and December 31, 2000
(Unaudited)............................................................................. F-36
Report of Independent Accountants ........................................................... F-37
Statement of Revenues and Direct Expenses of Global Energy Markets
purchased on March 16, 2001 - For the year ended
December 29, 2000 ...................................................................... F-38
Statement of Assets Acquired and Liabilities Assumed of Global Energy
Markets purchased on March 16, 2001 - As of December 29, 2000 .......................... F-39
Notes to Financial Statements ............................................................... F-40
F-1
CONSOLIDATED STATEMENT OF OPERATIONS
(Thousands of Dollars)
UNAUDITED UNAUDITED
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------------- -----------------------------
2001 2000* 2001 2000*
------------- ------------ ------------- -------------
Operating Revenues:
Retail $ 26,406 $ 42,843 $ 113,238 $ 155,828
Wholesale 2,999,393 407,602 6,114,380 822,171
Affiliated 286,407 238,785 845,362 497,601
--------- ------- --------- ---------
Total Operating Revenues 3,312,206 689,230 7,072,980 1,475,600
--------- ------- --------- ---------
Cost of Sales (Exclusive of depreciation
and amortization shown separately below):
Fuel for electric generation 132,531 93,463 338,943 216,524
Purchased energy and transmission 2,819,039 496,356 5,922,093 992,527
Cost of Sales 2,951,570 589,819 6,261,036 1,209,051
--------- ------- --------- ---------
Net Revenues 360,636 99,411 811,944 266,549
Other Operating Expenses:
Selling, general and administrative 50,169 9,001 104,757 28,753
Other operation 13,373 9,226 44,136 23,437
Maintenance 29,528 18,689 98,622 53,936
Depreciation and amortization 34,491 14,391 80,737 39,296
Taxes other than income taxes 16,389 15,989 50,681 41,386
------- ------ ------- -------
Total Operating Expenses 143,950 67,296 378,933 186,808
------- ------ ------- -------
Operating Income 216,686 32,115 433,011 79,741
Other Income and Expenses 702 1,113 4,938 3,384
Interest Charges:
Interest charges 35,001 11,694 78,593 24,269
Interest capitalized (2,094) (1,508) (4,545) (3,861)
------ ------ ------ ------
Total Interest Charges 32,907 10,186 74,048 20,408
------ ------ ------ ------
Consolidated Income Before Income Taxes,
Minority Interest, and Cumulative
Effect of Accounting Change 184,481 23,042 363,901 62,717
Federal and State Income Taxes 65,872 7,150 129,044 18,721
Minority Interest 962 1,133 3,646 1,133
--- ----- ----- -----
Consolidated Income Before Cumulative
Effect of Accounting Change 117,647 14,759 231,211 42,863
Cumulative Effect of Accounting Change (31,147)
----------- --------- ---------- ----------
Consolidated Net Income $ 117,647 $ 14,759 $ 200,064 $ 42,863
=========== ========= ========== ==========
See accompanying notes to consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.
F-2
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
UNAUDITED
NINE MONTHS
ENDED SEPTEMBER 30
----------------------------
2001 2000
------------- ------------
CASH FLOWS USED IN OPERATIONS:
Consolidated net income $ 200,064 $ 42,863
Cumulative effect of accounting change, net 31,147
---------- ---------
Consolidated income before cumulative effect of
accounting change, net 231,211 42,863
Deferred investment credit and income taxes, net 231,799 9,863
Depreciation and amortization 80,737 39,296
Unconsolidated subsidiary dividends in excess of
earnings 1,535
Minority interest in AGC, Inc. 3,646 1,133
Loss of plant retirements 4,972
Adverse purchase commitment (14,118)
Unrealized gains on commodity contracts, net (567,562)
Changes in certain assets and liabilities:
Accounts receivable, net (26,866) (193,655)
Affiliated accounts receivable/payable, net (45,906) (14,885)
Materials and supplies 6,584 7,489
Deposits (68,035)
Accounts payable 68,431 173,686
Taxes accrued 27,558 5,450
Purchased options 17,056 5,367
Prepaid taxes (133,211) (27,870)
Interest accrued 3,282 (1,320)
Payroll accrued 32,805
Accrued major maintenance 9,205 2,991
Customer deposits 17,250
Other, net (8,042) 1,454
--------- -------
(120,058) 44,251
--------- -------
CASH FLOWS USED IN INVESTING:
Acquisition of business and generating assets (1,548,612)
Construction expenditures (132,573) (125,320)
---------- ---------
(1,681,185) (125,320)
---------- ---------
CASH FLOWS FROM FINANCING:
Notes payable to Parent and affiliates 299,300 (16,350)
Issuance of long-term debt 396,580
Short-term debt, net 847,737 114,392
Funds on deposit with trustee 4,576
Parent company contribution 271,850 21,305
Dividends paid to minority shareholder (5,835) (2,160)
Dividends paid to Parent (42,000)
---------- ---------
1,809,632 79,763
---------- ---------
Net change in cash and temporary cash investments 8,389 (1,306)
Cash and temporary cash investments at January 1 420 1,668
---------- ---------
Cash and temporary cash investments at September 30 $ 8,809 $ 362
=========== ==========
F-3
UNAUDITED
NINE MONTHS
ENDED SEPTEMBER 30
---------------------------
2001 2000
------------ ------------
Supplemental Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 74,152 $ 31,654
Income taxes 1,105 41,079
- ---------
Non-cash investing activities:
On March 16, 2001, the Company acquired Global Energy Markets
from Merrill Lynch, which we refer to as the Energy Trading Business.
Effective June 29, 2001, the transaction was completed and Merrill
Lynch has a 1.967% equity membership interest in the Company. See Note
5 to the consolidated financial statements regarding the generating
asset transfers from Monongahela Power Company and Allegheny Energy,
Inc.
See accompanying notes to consolidated financial statements.
F-4
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
UNAUDITED
-----------------------------------------
SEPTEMBER 30, 2001 DECEMBER 31, 2000
------------------- -----------------
ASSETS:
Current Assets:
Cash and temporary cash investments $ 8,809 $ 420
Accounts receivable:
Nonaffiliated 211,781 190,823
Affiliates, net 25,548
Allowance for uncollectible accounts (2,874) (5,776)
Materials and supplies - at average cost:
Operating and construction 52,479 47,051
Fuel 27,571 33,044
Deposits 68,035
Deferred income taxes 11,907
Prepaid taxes 154,034 20,036
Commodity contracts 1,698,927 234,537
Other 5,026 3,856
---------- ---------
2,249,336 535,898
---------- ---------
Property, Plant and Equipment:
At original cost, including $192,468 and
$107,284 under construction 5,280,216 3,807,691
Accumulated depreciation (1,926,520) (1,754,823)
---------- --------
3,353,696 2,052,868
---------- --------
Investments including intangibles:
Excess of costs over net assets acquired
(net of amortization of $7.8 million) 373,958
Other 1,670 250
----------- ---------
375,628 250
----------- ---------
Deferred Charges 46,007 18,556
----------- ---------
Total $6,024,667 $2,607,572
=========== ==========
LIABILITIES AND MEMBERS' EQUITY:
Current Liabilities:
Long-term debt due within one year $ 83,507
Note payable to Parent and affiliates 452,550 $ 53,250
Short-term debt 913,502 165,765
Accounts payable 315,010 244,540
Accounts payable to affiliates, net 20,571
Deferred income taxes 214,812
Taxes accrued:
Federal and state income 32,367 6,856
Other 26,442 24,776
Customer deposits 17,250
Interest accrued 12,407 9,007
Payroll accrued 32,805
Commodity contracts 969,520 224,591
Other 13,719 4,813
---------- --------
3,083,891 754,099
---------- --------
F-5
UNAUDITED
-----------------------------------------
SEPTEMBER 30, 2001 DECEMBER 31, 2000
------------------- -----------------
Long-term Debt 892,714 563,433
--------- --------
Minority Interest 30,912 38,980
--------- --------
Deferred Credits and Other Liabilities:
Unamortized investment credit 64,622 65,823
Deferred income taxes 397,052 399,751
Other 35,028 25,843
--------- --------
496,702 491,417
--------- --------
Commitments and Contingencies (See Note 12)
Members' Equity 1,520,448 759,643
---------- ----------
Total $6,024,667 $2,607,572
========== ==========
- --------
See accompanying notes to consolidated financial statements.
F-6
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
UNAUDITED UNAUDITED
THREE MONTHS ENDED NINE MONTHS
SEPTEMBER 30 ENDED SEPTEMBER 30
----------------------------- ------------------------
2001 2000 2001 2000
-------------- ---------- ---------- ---------
Consolidated net income $117,647 $14,759 $200,064 $42,863
Other comprehensive income (loss):
Unrealized gains (losses) on cash flow hedges:
Cumulative effect of accounting
change - gain on cash flow hedges 1,478
Unrealized gain (loss) on cash flow
hedges for the period, net of
reclassification to
earnings 3,082 (1,478)
---------- --------- ---------- ---------
Net realized loss on cash flow hedges,
net of reclassification to earnings 3,082
---------- --------- ---------- ---------
Total other comprehensive income (loss) 3,082
---------- --------- ---------- ---------
Consolidated comprehensive income $120,729 $14,759 $200,064 $42,863
========== ========= ========== ==========
- --------
See accompanying notes to consolidated financial statements.
F-7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. The Notes to Consolidated Financial Statements of Allegheny Energy
Supply Company, LLC (the Company) for the year ended December 31, 2000, should
be read with the accompanying consolidated financial statements and the
following notes. The accompanying consolidated financial statements appearing on
pages F-2 through F-7 and these notes to consolidated financial statements are
unaudited. In the opinion of the Company, such consolidated financial statements
together with these notes contain all adjustments (which consist only of normal
recurring adjustments) necessary to present fairly the Company's financial
position as of September 30, 2001, the results of operations for three and nine
months ended September 30, 2001 and 2000, cash flows for the nine months ended
September 30, 2001 and 2000, and comprehensive income for the three and nine
months ended September 30, 2001 and 2000. Certain prior period amounts in these
financial statements and notes have been reclassified for comparative purposes.
2. On March 16, 2001, the Company acquired Global Energy Markets (the
Energy Trading Business) the energy commodity marketing and trading unit of
Merrill Lynch Capital Services, Inc. (Merrill Lynch). The acquired business,
which is now called Allegheny Energy Global Markets, LLC (Allegheny Energy
Global Markets), conducts the Company's wholesale marketing, energy trading,
fuel procurement and risk management activities and provides customers with
customized energy management solutions to assist in meeting energy requirements.
The Company's acquisition of the Energy Trading Business from Merrill
Lynch included the following:
o The majority of the existing energy trading contracts of the
Energy Trading Business
o Employees engaged in energy trading activities that accepted
employment with Allegheny Energy Global Markets
o Rights to certain intellectual property
o Memberships in exchanges or clearinghouses
o Other tangible property
The identifiable assets acquired were recorded at estimated fair values.
Consideration paid and assets acquired were as follows:
(Millions of Dollars)
Cash purchase price $489.2
Commitment for equity interest in subsidiary 115.0
Direct costs of the acquisition 6.4
------
Total acquisition cost 610.6
------
Less: Estimated fair value of assets acquired
Commodity contracts 218.3
Property, plant, and equipment 2.5
Other assets 1.4
------
Excess of cost over net assets acquired $388.4
======
The Company acquired this business for $489.2 million in cash plus the
issuance of a 1.967% equity membership interest in itself. The cash portion of
the transaction closed on March 16, 2001, and was
financed by issuing $400.0 million of 7.80% notes due 2011 and issuing
short-term debt for the balance. By order dated May 30, 2001, the Securities and
Exchange Commission (SEC) authorized the issuance of an equity membership
interest in the Company to Merrill Lynch. Effective June 29, 2001, the
transaction was completed and Merrill Lynch now has a 1.967% equity ownership in
the Company.
F-8
The acquisition was recorded using the purchase method of accounting
and, accordingly, the consolidated statement of operations includes the results
of Allegheny Energy Global Markets, beginning March 16, 2001.
The excess of costs over net assets acquired will be amortized by the
straight-line method using a 15-year amortization period. However, effective
January 1, 2002, the Company will adopt the Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and
Other Intangible Assets" and, accordingly, will cease the amortization of
goodwill and account for goodwill on an impairment-only approach. The Company
will be evaluating the effect of adopting SFAS No. 142 on its results of
operations and financial position prior to its adoption of the standard on
January 1, 2002.
3. At September 30, 2001, the Company owned all of the outstanding
membership interests of its subsidiary, Allegheny Energy Global Markets, LLC and
77.03% of the outstanding common stock of its subsidiary, Allegheny Generating
Company (AGC). The consolidated financial statements include the accounts of the
Company and its subsidiary companies after elimination of intercompany
transactions.
4. On May 3, 2001, the Company completed the acquisition of 1,710
megawatts (MW) of natural gas-fired generating capacity in Illinois, Indiana,
and Tennessee from Enron North America (Enron). We refer to these assets as the
Midwest Assets. The three generating plants will increase the portfolio of
generating assets and commodity contracts managed by Allegheny Energy Global
Markets. The $1.053 billion purchase price was financed with short-term debt of
$550 million from a group of credit providers, a $325 million parent loan, a
$175 million parent equity contribution, and other short-term debt. The Company
expects to refinance the short-term debt with a long-term source of financing in
2001.
5. On October 5, 2000, the Ohio Public Utilities Commission (Ohio PUC)
approved a settlement to implement a restructuring plan for Monongahela Power
Company (Monongahela Power), a regulated utility subsidiary of Allegheny Energy.
The restructuring plan allowed Monongahela Power to transfer its Ohio
jurisdictional generating assets to the Company at net book value. Monongahela
Power transferred the approximately 352 MW of Ohio and Federal Energy Regulatory
Commission, or FERC, jurisdictional generating assets to the Company on June 1,
2001.
In January 2001, Allegheny Energy, Inc. (Allegheny Energy) purchased 83
MW of Potomac Electric Power Company's share in the 1,711 MW Conemaugh
generating station in west-central Pennsylvania. Allegheny Energy transferred
the subsidiary owning these generating assets to the Company on June 29, 2001.
In 1999, Allegheny Energy Units No. 1 & 2, LLC, a subsidiary of
Allegheny Energy, completed construction of and placed into operation two 44 MW,
simple-cycle gas combustion turbines in Springdale, Pennsylvania. Allegheny
Energy merged this subsidiary with the Company on June 1, 2001.
The net effect of the generating assets transferred to the Company are
shown below:
MONONGAHELA ALLEGHENY ENERGY
POWER UNITS NO. 1 & 2 CONEMAUGH TOTAL
----------- ---------------- --------- -----
(MILLIONS OF DOLLARS)
Total Assets:
Current assets $ 5.9 $ 1.4 $ 7.3
Property, plant, and equipment 68.4 46.8 $79.0 194.2
Allegheny Generating Company 5.9 5.9
Deferred charges .1 .1
----- ----- ----- ------
Total $80.3 $48.2 $79.0 $207.5
===== ===== ===== ======
Total Liabilities and Members' Equity:
Current Liabilities $ 2.9 $ .5 $ 3.4
Long-term debt 15.9 15.9
Deferred credits and other liabilities 12.7 1.6 14.3
Members' equity 48.8 46.1 $79.0 173.9
----- ----- ----- -----
Total $80.3 $48.2 $79.0 $207.5
===== ===== ===== ======
The generating assets were transferred to the Company at net book value.
F-9
In connection with the transfer of Monongahela Power's generating
assets, Monongahela Power continues to be co-obligor with respect to $15.9
million pollution control debt.
In connection with the transfer of Monongahela Power's generating
assets, the Company received a 4.03% ownership interest of AGC, which increased
the Company's ownership of AGC from 73% to 77.03%. The remaining 22.97% interest
in AGC is owned by Monongahela Power and is represented in the Company's balance
sheet as Minority Interest.
6. The Company enters into contracts for the purchase and sale of
electricity in the wholesale market. The Company's wholesale market activities
consist of buying and selling over-the-counter contracts for the purchase and
sale of electricity. The majority of these are forward contracts representing
commitments to purchase and sell at fixed prices in the future. These contracts
require physical delivery. The Company also uses option contracts for the
purchase and sale of electricity at fixed prices in the future. These option
contracts also require physical delivery but may result in financial settlement.
On March 16, 2001, the Company acquired the Energy Trading Business.
This acquisition significantly increased the volume and scope of the Company's
energy commodity marketing and trading activities. The Energy Trading Business
activities include the marketing and trading of electricity, natural gas, oil
and other energy commodities using primarily over-the-counter contracts and
exchange-traded contracts, such as those traded on the New York Mercantile
Exchange (NYMEX).
As part of the acquisition of the Energy Trading Business, the Company
obtained the contractual right to control 1,000 MW of natural gas-fired
generating capacity at three generating stations in Southern California, with
capacity at these three generating stations totaling about 4,000 MW. In this
transaction, the Company acquired the contractual rights through 2018 to call up
to 25% of the total available generating capacity of the three stations at a
price based on an indexed gas price and a heat rate that varies with the amount
of energy called. Under the contractual right to control, the Company pays a
monthly premium of approximately $3.5 million (approximately $42 million
annually) that increases to approximately $4.2 million (approximately $51
million annually) over the term of the transaction.
Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," requires
contracts entered into in connection with energy trading activities to be marked
to fair value on the consolidated balance sheet, with all changes in fair value
recorded as gains and losses on the statement of operations. The Company records
the contracts used in its trading activities at fair value on the consolidated
balance sheet, with all changes in fair value recorded as gains and losses on
the consolidated statement of operations in "Operating Revenues - Wholesale."
Fair values for exchange-traded instruments, principally futures and certain
options, are based on quoted market prices. In establishing the fair value of
commodity contracts that do not have quoted market prices, such as physical
contracts, over-the-counter options and swaps, management makes estimates using
available market data and pricing models. Factors such as commodity price risk,
operational risk, and credit risk of counterparties are evaluated in
establishing the fair value of these commodity contracts.
The Company has contracts that are unique due to their long-term nature
and are valued using a proprietary pricing model. Inputs to the model include
estimated forward gas and power prices, interest rates, estimates of market
volatility for gas and power prices and the correlation of gas and power prices.
The estimated fair value represents management's best estimate of an amount that
could be realized in an actual transaction. However, the fair value could vary
materially from the amount that could be actually realized. The Company has not
recorded any reserves for its commodity contracts under SFAS No. 5, "Accounting
for Contingencies."
The fair value of commodity contracts, which represent the net
unrealized gains and loss positions are recorded as assets or liabilities,
respectively, after applying the appropriate counterparty netting agreements in
accordance with FASB Interpretation No. 39. At September 30, 2001, the fair
value of "Commodity Contract" assets was $1.7 billion and the fair value of
"Commodity Contract" liabilities was $969.5 million. Net unrealized gains of
$387.1 million and $567.6 million, before tax, were recorded to the consolidated
statement of operations in "Operating Revenues - Wholesale" to reflect the
change in fair value of the energy commodity contracts for the third quarter and
first nine months of 2001, respectively. See Note 10 for additional information
regarding commodity contracts and unrealized gains and losses.
F-10
7. The West Virginia Legislature passed House Concurrent Resolution 27
on March 11, 2000, approving an electric deregulation plan submitted by the West
Virginia Public Service Commission. However, further action by the Legislature,
including the enactment of certain tax changes regarding preservation of tax
revenues for state and local government, is required prior to the implementation
of the restructuring plan for customer choice. The 2001 legislative session
ended April 14, 2001, with no final legislative activity regarding
implementation of the deregulation plan taken. The Company anticipates that
legislative action to implement the West Virginia plan will be sought in 2002.
Among the provisions of the plan are the following:
-- Customer choice will begin for all customers when the plan is
implemented.
-- Monongahela Power, a regulated utility affiliate, is permitted to
file a petition seeking West Virginia Public Service Commission
approval to transfer its West Virginia jurisdictional generating
assets, approximately 2,111 MW, to the Company, at net book
value.
8. On May 25, 2000, The Potomac Edison Company (Potomac Edison), filed
an application with the Virginia State Corporation Commission to separate its
approximately 380 MW of generating assets, excluding the hydroelectric assets
located within the state of Virginia, from its transmission and distribution
assets. On July 11, 2000, the Virginia State Corporation Commission issued an
order approving Potomac Edison's separation plan permitting the transfer, at net
book value, of its Virginia jurisdictional generating assets to the Company.
Potomac Edison transferred these assets to the Company on August 1, 2000.
On August 10, 2000, Potomac Edison applied to the Virginia State
Corporation Commission to transfer the five MW of hydroelectric assets located
within the state of Virginia to its subsidiary Green Valley Hydro, LLC. On
December 14, 2000, the Virginia State Corporation Commission approved the
transfer. In June 2001, Potomac Edison transferred these assets to Green Valley
Hydro, LLC and distributed its ownership of Green Valley Hydro, LLC to Allegheny
Energy. Green Valley Hydro, LLC will become a subsidiary of the yet to be formed
parent holding company of the Company as proposed in the U-l application filed
with the SEC on November 29, 2001.
9. The consolidated statement of comprehensive income provides the
components of comprehensive income for the three and nine months ended September
30, 2001 and September 30, 2000.
On January 1, 2001, the Company recorded an asset of $1.5 million on its
balance sheet based on the fair value of its two cash flow hedge contracts and
recorded an offsetting amount in other comprehensive income as a change in
accounting principle in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The amounts accumulated in other
comprehensive income related to these contracts were reclassified to earnings
during July and August of 2001 when the hedged transactions were executed. A
loss of $5.0 million, before tax ($3.1 million net of tax), was reclassified to
purchased energy and transmission during the third quarter of 2001 for these
cash flow hedge contracts. See Note 10 for additional details.
10. In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently
amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133 - an
amendment of FASB Statement No. 133" and SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of FASB
Statement No. 133." Effective January 1, 2001, the Company implemented the
requirements of these accounting standards.
These statements establish accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, collectively referred to as derivatives, and for hedging
activities. The statements require that an entity recognize derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The statements also require that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. The accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
earnings or other comprehensive income and requires that a company formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS No. 133 is expected to increase the volatility in
reported earnings and other comprehensive income.
F-11
On January 1, 2001, the Company recorded an asset of $1.5 million on its
balance sheet based on the fair value of its two cash flow hedge contracts. An
offsetting amount was recorded in other comprehensive income as a change in
accounting principle as provided by SFAS No. 133. The Company has two principal
risk management objectives regarding these cash flow hedge contracts. First, the
Company has a contractual obligation to service the instantaneous demands of its
customers. When this instantaneous demand exceeds the Company's electric
generating capability, it must enter into contracts providing for the purchase
of electricity to meet this shortage. Second, the price of electricity is
subject to price volatility. This volatility is the result of many factors,
including the weather, and tends to be the highest during the summer months. To
ensure that energy market movements do not cause a significant degradation in
earnings the Company enters into fixed price electricity purchase contracts.
The amounts accumulated in other comprehensive income related to these
contracts were reclassified to earnings during July and August of 2001 when the
hedged transactions were executed. A loss of $5.0 million, before tax ($3.1
million net of tax), was reclassified to purchased energy and transmission
during the third quarter of 2001 for these cash flow hedge contracts.
The Company also has certain option contracts that meet the derivative
criteria in SFAS No. 133, which did not qualify for hedge accounting. On January
1, 2001, the Company recorded an asset of $0.1 million and a liability of $52.4
million on its balance sheet based on the fair value of these contracts. The
majority of this liability was related to one contract. The terms of this
three-year contract entered into on January 1, 1999, provides the counterparty
with the right to purchase, at a fixed price, 270 MW of electricity per hour
until December 31, 2001. The fair value of this contract represented a liability
of approximately $52.3 million on January 1, 2001. The liability associated with
this contract will reduce to zero at December 31, 2001, with the expiration of
the contract. The fair value of these contracts will fluctuate over time due to
changes in the underlying commodity prices that are influenced by various
factors, including the weather and availability of regional electric generation
and transmission capacity. In accordance with SFAS No. 133, the Company recorded
a charge of $31.1 million against earnings net of the related tax effect ($52.3
million before tax) for these contracts as a change in accounting principle on
January 1, 2001. As of September 30, 2001, the net fair value of these contracts
was $1.1 million. The total change in fair value of $51.2 million for these
contracts during the first nine months of 2001 was recorded as a gain in
"Operating Revenues - Wholesale" on the statement of operations.
11. Substantially all of the employees of Allegheny Energy are employed
by Allegheny Energy Service Corporation (AESC), which performs services at cost
for the Company and its affiliates in accordance with the Public Utility Holding
Company Act of 1935 (PUHCA). Through AESC, the Company is Responsible for Its
proportionate share of services provided by AESC. The total billings by AESC
(including capital) to the Company were $30.4 million and $21.4 million for the
three months ended September 30, 2001 and 2000, respectively, and $89.9 million
and $63.2 million for the nine months ended September 30, 2001 and 2000,
respectively. The President of Allegheny Energy Global Markets and all current
employees of this business are now employed directly by Allegheny Energy Global
Markets. The employees of the Lincoln generating facility are employees of
Allegheny Energy Supply Lincoln Generating Facility, LLC, a wholly-owned
subsidiary of the Company.
The Company and its subsidiary, AGC, use an Allegheny Energy internal
money pool as a facility to accommodate intercompany short-term borrowing needs,
to the extent that certain companies have funds available. The variable interest
rate on the money pool is the lesser of the previous days federal funds rate or
the seven-day commercial paper rate less four basis points. The Company had $2.4
million and $53.3 million in money pool borrowings outstanding at September 30,
2001, and December 31, 2000, respectively. The Company also received a loan of
$325.0 million, at a fixed rate of 6.72%, from its parent, Allegheny Energy, for
the purpose of acquiring the Midwest Assets.
The Company supplies electricity to the regulated utility subsidiaries
of Allegheny Energy in accordance with agreements approved by the FERC including
electricity supplied to West Penn Power Company (West Penn) Potomac Edison, and
Monongahela Power to meet their retail load requirements as the
provider-of-last-resort during the transition period for deregulation plans
approved in Pennsylvania, Maryland, and Ohio. The revenue from these sales is
reported separately on the consolidated statement of operations as "Operating
Revenues - Affiliated."
F-12
12. COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL MATTERS AND LITIGATION
The Company is subject to various laws, regulations and uncertainties as
to environmental matters. Compliance may require it to incur substantial
additional costs to modify or replace existing and proposed equipment and
facilities and may adversely affect the cost of future operations.
The Environmental Protection Agency's (EPA) nitrogen oxides (NO(x))
State Implementation Plan (SIP) call regulation has been under litigation and,
on March 3, 2000, the District of Columbia Circuit Court of Appeals issued a
decision that upheld the regulation. However, state and industry litigants filed
an appeal of that decision in April 2000. On June 23, 2000, the Court denied the
request for the appeal. Although the Court did issue an order to delay the
compliance date from May 1, 2003 until May 31, 2004, both the Maryland and
Pennsylvania state rules to implement the EPA NO(x) SIP call regulation still
require compliance by May 1, 2003. West Virginia has issued a proposed rule that
would require compliance by May 31, 2004. However, the EPA Section 126 petition
regulation also requires the same level of NO(x) reductions as the EPA NO(x) SIP
call regulation with a May 1, 2003 compliance date. The EPA Section 126 petition
rule is also under litigation in the District of Columbia Circuit Court of
Appeals. In August 2001, the Court issued an order that suspends the Section 126
petition rule May 1, 2003 compliance date pending EPA review of growth factors
used to calculate the state NO(x) budgets. The Company's compliance with such
stringent regulations will require the installation of expensive post-combustion
control technologies on most of its power stations. The Company's construction
forecast includes the expenditure of $162.3 million of capital costs during the
2002 through 2004 period to comply with these regulations.
On August 2, 2000, Allegheny Energy received a letter from the EPA
requiring it to provide certain information on the following 10 electric
generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's
Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. The
Company and Monongahela Power now own these electric generating stations. The
letter requested information under Section 114 of the federal Clean Air Act to
determine compliance with federal Clean Air Act and state implementation plan
requirements, including potential application of federal New Source Review. In
general, these standards can require the installation of additional air
pollution control equipment upon the major modification of an existing facility.
Allegheny Energy submitted these records in January 2001. The eventual outcome
of the EPA investigation is unknown.
Similar inquiries have been made of other electric utilities and have
resulted in enforcement proceedings being brought in many cases. The Company
believes its generating facilities have been operating in accordance with the
Clean Air Act and the rules implementing the Act. The experience of other
utilities, however, suggests that, in recent years, the EPA may well have
revised its interpretation of the rules regarding the determination of whether
an action at a facility constitutes routine maintenance, which would not trigger
the requirements of the federal New Source Review, or a major modification of
the facility, which would require compliance with the federal New Source Review.
If the federal New Source Review was to be applied to these generating stations,
in addition to the possible imposition of fines, compliance would entail
significant expenditures.
In December 2000, the EPA issued a decision to regulate coal-fired and
oil-fired electric utility mercury emissions under Title III, Section 112 of the
1990 Clean Air Act Amendments (CAAA). The EPA plans to issue a proposed
regulation by December 2003 and a final regulation by December 2004. The timing
and level of required mercury emission reductions are unknown at this time.
The Attorney General of the State of New York and the Attorney General
of the State of Connecticut in their letters dated September 15, 1999, and
November 3, 1999, respectively, notified Allegheny Energy of their intent to
commence civil actions against Allegheny Energy or certain of its subsidiaries
alleging violations at the Fort Martin Power Station under the federal Clean Air
Act, including the new source performance standards, which require existing
power plants that make major modifications to comply with the same emission
standards applicable to new power plants. Other governmental authorities may
commence similar actions in the future. Fort Martin is a station located in West
Virginia and is now jointly owned by the Company and Monongahela Power. Both
Attorney Generals stated their intent to seek injunctive relief and penalties.
In addition, the Attorney General of the State of New York in his letter
indicated that he might assert claims under the state common law of public
nuisance seeking to recover, among other things, compensation for alleged
environmental damage caused in New York by the
F-13
operation of Fort Martin Power Station. At this time, Allegheny Energy and its
subsidiaries are not able to determine what effect, if any, these actions
threatened by the Attorney Generals of New York and Connecticut may have on
them.
On June 19, 2001, the FERC initiated proceedings to ascertain whether
and to what extent sellers of electricity in California and the other Western
States may owe refunds for the period from October 1, 2000 through April 30,
2001 for possible overcharges in the sale of electricity into such markets. The
Company was a seller in the Western markets beginning on or about March 16,
2001. In addition, Nevada Power Company (NPC) filed a complaint against the
Company with FERC, on December 7, 2001, contending that the price in three
forward sales agreements, which were entered into by the Energy Trading Business
between December 2000 and February 2001, was excessive and should be
substantially reduced by FERC. As of September 30, 2001, the estimated fair
value of the contracts with NPC was approximately $20 million. Allegheny Energy
has intervened in the FERC refund proceedings. Based upon its information and
belief, Allegheny Energy believes that NPC's complaint is without merit and that
its potential liability, if any, under the aforementioned proceedings under the
FERC Order and the NPC complaint is of a nature that will not have a material
adverse effect upon its financial condition. Initial indications arising from
the proceedings confirm such belief. Allegheny Energy has also intervened in the
various other FERC related proceedings relating to the FERC Order and has sought
rehearing of the FERC's market mitigation rules and related court proceedings,
as they would affect future markets in which Allegheny Energy conducts its
business and operations.
In September 2001, the Utility Workers Union of America (UWUA) filed a
petition with Pennsylvania Public Utility Commission. The UWUA has requested
that the Pennsylvania Public Utility Commission determine that the initial
public offering of common stock of the proposed new parent holding company of
the Company and the subsequent distribution of shares of common stock of that
holding company to Allegheny Energy's stockholders be treated under the
Pennsylvania deregulation settlement order as a "sale" of the generating assets
previously transferred to the Company by West Penn. If the UWUA is successful in
its claim and the initial offering and distribution constitute a sale, Allegheny
Energy will be required to use the proceeds of the initial offering to offset
and reduce the $670 million in stranded generating costs that West Penn is
entitled to recover from its Pennsylvania customers as a surcharge. The UWUA
contends that the initial public offering should be used to value the generating
assets transferred from West Penn and that this amount be returned to West Penn.
Although the Company does not believe that the UWUA petition has merit, the
Company cannot predict the outcome of the Pennsylvania Public Utility Commission
determination or, if the UWUA is successful in its claim, its effect on the
initial public offering and distribution.
In the normal course of business, the Company and its subsidiaries
become involved in various legal proceedings. The Company and its subsidiaries
do not believe that the ultimate outcome of these proceedings will have a
material effect on their financial position.
CAPACITY PURCHASE COMMITMENTS
In May 2001, the Company signed a 15-year agreement with Las Vegas
Cogeneration II, L.L.C. scheduled to commence on September 1, 2002. This
agreement relates to the contractual control of 222 MW of a combined cycle
natural gas-fired electric generating facility currently under construction by a
third-party. Based on an assessment of the construction status of the facility,
the Company has concluded that it is reasonably possible that the facility will
meet the September 1, 2002 scheduled commercial operation date for the facility
under the terms of the agreement. If the facility fails to meet commercial
operations by September 1, 2002, other than as a result of force majeure of the
Company's action or inaction, the Company will not be required to make capacity
payments to Las Vegas Cogeneration II, L.L.C. until the facility achieves
commercial operation. In addition, Las Vegas Cogeneration II, L.L.C. would be
required to pay the Company $40,000 per day beginning October 1, 2002, for up to
seventy-five days that commercial operation occurs after September 1, 2002, plus
any amounts recovered from the contractor building the facility (or any other
entity responsible for such delay) for days beyond seventy-five days. Also, the
term of the agreement shall not begin after April 30, 2003, unless the Company
elects in its sole discretion to continue the agreement.
As of September 30, 2001, the Company estimates the fair value of the
agreement with Las Vegas Cogeneration II, L.L.C. to range from a negative $22
million to a negative $77 million assuming the facility is ready for commercial
operation by September 1, 2002. However, based on discussions that the Company
has had with Las Vegas Cogeneration II, L.L.C. and the construction contractor,
the Company has concluded that the
F-14
construction of the facility is, as of September 30, 2001, in a relatively early
phase. The Company does not believe that at this time it can adequately
determine that completion of the facility by September 1, 2002, is probable, and
has therefore, not recorded a liability for the fair value of this contract as
of September 30, 2001.
The table below shows the amount of capacity payments for each of the
next four years and in aggregate for the term of the agreement, as of September
30, 2001.
Amount
(Millions of Dollars)
---------------------
2001 $-
2002 10.8
2003 32.4
2004 32.4
2005 32.4
Thereafter 378.0
------
Total Capacity Payments $486.0
======
In June 2001, the Company was awarded natural gas transportation capacity of
50,000 dekatherms per day on the Sonoran Pipeline in the southwestern United
States. This transportation capacity has a term of 31 years. The Company will be
obligated to make annual payments of $7.7 million for the term of the contract
starting in July 2003.
CONTRACTUAL COMMITMENTS FROM THE ENERGY TRADING BUSINESS ACQUISITION
The purchase agreement for the Energy Trading Business provides that
Allegheny Energy shall use its best efforts to contribute to the Company the
generating capacity from Monongahela Power's West Virginia jurisdictional
generating assets by September 16, 2002. If, after using its best efforts to
comply with this provision of the purchase agreement, Allegheny Energy is
prohibited by law from contributing to the Company those generating assets or
substantially all of the economic benefits associated with such assets, then
Merrill Lynch shall have the right to require Allegheny Energy to repurchase
all, but not less than all, of Merrill Lynch's equity interest in the Company
for $115 million plus interest calculated from March 16, 2001.
The purchase agreement also provides that, if Allegheny Energy has not
completed an initial public offering involving the Company within two years of
March 16, 2001, Merrill Lynch has the right to sell its equity membership
interest in the Company to Allegheny Energy for $115 million plus interest from
March 16, 2001.
LEASE TRANSACTION
In November 2001, we completed an operating lease transaction, known as
the St. Joseph lease transaction, in connection with a 630 MW intermediate-load
and peaking natural gas-fired facility located in St. Joseph County, Indiana.
Commercial operation is expected to begin in 2003 for the peaking facility and
in 2005 for the intermediate-load facility. The St. Joseph lease transaction was
structured to finance the construction of both the peaking and intermediate
facility with a maximum commitment amount of $460 million. We will lease the
plant from a non-affiliated lessor special purpose entity when the construction
has been completed. Lease payments, to be recorded as rent expense, are
estimated at $2.8 million per month, commencing on final completion of the
entire facility in 2005 and continuing through November 2007. After November
2007, we have the right to negotiate renewal terms or purchase the facility for
the lessor's investment or sell the facility and pay the amount, if any, by
which the lessor's investment exceeds the sale proceeds, up to a maximum
recourse amount of approximately $392 million.
Prior to closing the St. Joseph lease transaction, in April 2001, we
consummated an operating equipment-lease transaction structured to finance the
purchase of turbines and transformers with a maximum commitment amount of $150
million. The St. Joseph lease transaction included a transfer between lessors of
some of the equipment previously financed in this equipment lease. As a result,
the commitment in the equipment lease has
F-15
been reduced to approximately $43 million. The remainder of the equipment
financed in the equipment lease will be used for another project.
Included in the St. Joseph lease transaction loan to us of $380 million
from the non-affiliated lessor special purpose entity. We are required to repay
part of the loan monthly during the lease construction period, based on
project cost funding requirements. Loan repayments are estimated as $5.5 million
in 2001, $157.6 million in 2002, $156.8 million in 2003, and $60.1 million in
2004. On the closing date of the lease transaction, we repaid approximately $4.0
million of the loan and used approximately $376.0 million of the net proceeds to
refinance existing affiliated and non-affiliated short-term debt.
13. JOINTLY OWNED ELECTRIC UTILITY PLANTS
The Company owns a 5% interest, approximately 83 MW, in coal-fired
generating capacity of the Conemaugh Generating Station near Johnstown,
Pennsylvania and an interest in seven generating stations with Monongahela
Power. The investments associated with these generating stations are recorded by
the Company based on percentage of station undivided ownership interest. As of
September 30, 2001, the investment and accumulated depreciation in these
generating stations was as follows:
OWNERSHIP UTILITY PLANT ACCUMULATED
GENERATING STATION PERCENTAGE INVESTMENT DEPRECIATION
------------------- ----------- --------------- -------------
(Millions of Dollars)
Conemaugh 4.86% $79.2 $2.0
Albright 41.49% 50.6 38.8
Fort Martin 80.86% 375.4 157.7
Harrison 78.73% 962.5 418.9
Hatfield's Ferry 76.60% 423.5 226.4
Pleasants 78.73% 830.1 422.6
Rivesville 14.92% 8.5 5.5
Willow Island 14.92% 15.1 8.9
14. The table below provides a roll-forward of the Company's members'
equity account from December 31, 2000, to September 30, 2001:
(Millions of Dollars)
---------------------
Members' Equity:
Balance at December 31, 2000 $759.6
Consolidated net income for nine months ended September 30, 2001 231.2
Cumulative effect of accounting change (31.1)
Allegheny Energy equity contributions 271.8
Allegheny Energy and Monongahela Power generating asset transfers 173.9
Issuance of membership interest 115.0
--------
Balance at September 30, 2001 $1,520.4
========
15. Letters of credit are purchased guarantees that ensure our
performance or payment to third parties, in accordance with certain terms and
conditions, and amount to $348.4 million of the $410.8 million available as of
September 30, 2001.
F-16
REPORT OF INDEPENDENT ACCOUNTANTS
To Allegheny Energy, Inc., the Sole Member of
Allegheny Energy Supply Company, LLC
In our opinion, the accompanying balance sheets and the related statements of
income, of member's capital and of cash flows present fairly, in all material
respects, the financial position of Allegheny Energy Supply Company, LLC (the
Company) at December 31, 2000 and 1999, and the results of its operations and
its cash flows for the year ended December 31, 2000 and from November 18, 1999
(inception date) through December 31, 1999, in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 12, 2001
F-17
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
CONSOLIDATED STATEMENT OF OPERATIONS
------------------------------------
(Thousands of Dollars)
From
November 18, 1999
Year Ended Inception Date to
December 31, December 31,
2000* 1999*
---------- -----------------
Operating Revenues:
Retail $ 197,189 $ 21,283
Wholesale 1,285,102 73,259
Affiliated 777,281 46,332
---------- --------
Total Operating Revenues 2,259,572 140,874
---------- --------
Cost of Sales (Exclusive of depreciation
and amortization shown separately below):
Fuel for electric generation 317,198 18,081
Purchased energy and transmission 1,522,465 84,448
---------- --------
Cost of Sales 1,839,663 102,529
---------- --------
Net Revenues 419,909 38,345
Other Operating Expenses:
Selling, general and administrative 49,129 5,298
Other operation 32,217 2,310
Maintenance 80,831 4,286
Depreciation and amortization 55,284 7,975
Taxes other than income taxes 58,455 5,506
---------- --------
Total Operating Expenses 275,916 25,375
---------- --------
Operating Income 143,993 12,970
Other Income and Expenses 3,542 1,159
Interest Charges:
Interest charges 37,795 2,305
Interest capitalized (4,337) (212)
---------- --------
Total Interest Charges 33,458 2,093
---------- --------
Consolidated Income Before Income Taxes,
Minority Interest, and Cumulative
Effect of Accounting Change 114,077 12,036
Federal and State Income Taxes 36,081 2,504
Minority Interest 2,508
---------- --------
Consolidated Income Before Cumulative
Effect of Accounting Change 75,488 9,532
Cumulative Effect of Accounting Change
---------- --------
Consolidated Net Income $ 75,488 $ 9,532
========== ========
See accompanying notes to consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.
F-18
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
CONSOLIDATED STATEMENT OF MEMBER'S EQUITY
FROM
NOVEMBER 18, 1999
YEAR ENDED INCEPTION DATE TO
DECEMBER 31, DECEMBER 31,
2000 1999
----------- -----------------
(in thousands)
BALANCE AT BEGINNING OF PERIOD ................. $512,699
ADD:
Member's capital contributions ............. 260,738 $506,597
Consolidated net income .................... 75,488 9,532
-------- --------
336,226 516,129
DEDUCT:
Return of member's capital contributions ... 22,282
Dividends paid to Parent ................... 67,000 3,430
-------- --------
89,282 3,430
BALANCE AT END OF PERIOD ....................... $759,643 $512,699
======== ========
- ----------
See accompanying notes to the consolidated financial statements.
F-19
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
FROM
NOVEMBER 18, 1999
YEAR ENDED INCEPTION DATE TO
DECEMBER 31, DECEMBER 31,
2000 1999*
----------- -----------------
(in thousands)
CASH FLOWS FROM OPERATIONS:
Consolidated net income ....................... $ 75,488 $ 9,532
Deferred investment credit and income
taxes, net ................................. 6,740 (2,155)
Depreciation and amortization ................. 55,284 7,975
Loss on plant retirements ..................... 7,555
Adverse purchase commitment ................... (14,118) (4,091)
Commodity contracts ........................... (8,392)
Changes in certain assets and liabilities:
Accounts receivable, net .................... (105,923) (45,365)
Affiliated accounts receivable/payable,
net ...................................... 27,892 6,975
Materials and supplies ...................... 6,055 (748)
Accounts payable ............................ 133,352 27,233
Taxes accrued ............................... 9,481 7,244
Purchased options ........................... 6,965 (8,521)
Prepaid taxes ............................... (3,966)
Other current liabilities ................... (4,026) (3,038)
Other, net .................................... 1,430 1,147
--------- --------
193,817 (3,812)
--------- --------
CASH FLOWS FROM INVESTING:
Other investments ............................. (250)
Construction expenditures ..................... (177,123) (50,769)
--------- --------
(177,373) (50,769)
--------- --------
CASH FLOWS FROM FINANCING:
Notes payable to Parent and affiliates ........ (17,403) 21,200
Retirement of long-term debt .................. (130,000)
Commercial paper .............................. 165,766
Funds on deposit with trustee ................. 4,576
Parent company contribution ................... 26,869 12,286
Return of member's capital contribution ....... (500)
Dividends paid to Parent ...................... (67,000) (3,430)
--------- --------
(17,692) 30,056
--------- --------
Net change in cash and temporary investments .... (1,248) (24,525)
Net change in cash and temporary investments
at beginning of period ........................ 1,668 26,193
--------- --------
Cash and temporary cash investments at
December 31 ................................... $ 420 $ 1,668
========= ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) ........ $ 44,312 $ 99
Income taxes ................................ $ 38,019 $ 117
- ----------
See accompanying notes to the consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.
F-20
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
CONSOLIDATED BALANCE SHEET
DECEMBER 31, DECEMBER 31,
2000 1999*
----------- -----------
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and temporary cash investments ......... $ 420 $ 1,668
Accounts receivable:
Nonaffiliated ............................. 190,823 80,261
Affiliates ................................ 14,253
Allowance for uncollectible accounts ...... (5,776) (1,137)
Materials and supplies--at average cost:
Operating and construction ................ 47,051 25,649
Fuel ...................................... 33,044 30,647
Deferred income taxes ....................... 11,907 10,467
Prepaid taxes ............................... 20,036 9,904
Commodity contracts ......................... 234,537
Other ....................................... 3,856 1,101
----------- -----------
535,898 172,813
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
At original cost, including $107,284
and $86,147 under construction ............ 3,807,691 2,060,040
Accumulated depreciation .................... (1,754,823) (940,672)
----------- -----------
2,052,868 1,119,368
----------- -----------
INVESTMENTS:
Allegheny Generating Company--common stock .. 69,521
Other ....................................... 250
----------- -----------
250 69,521
----------- -----------
DEFERRED CHARGES .............................. 18,556 13,804
----------- -----------
Total ....................................... $ 2,607,572 $ 1,375,506
=========== ===========
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Note payable to Parent and affiliates ....... $ 53,250 $ 21,200
Short-term debt ............................. 165,765
Accounts payable ............................ 244,470 99,104
Accounts payable to affiliates .............. 20,571
Taxes accrued:
Federal and state income .................. 6,856 5,475
Other ..................................... 24,776 12,808
Adverse power purchase commitment ........... 24,289
Commodity contracts ......................... 224,591
Other ....................................... 13,820 7,825
----------- -----------
754,099 170,701
----------- -----------
LONG-TERM DEBT ................................ 563,433 356,239
----------- -----------
MINORITY INTEREST ............................. 38,980
----------- -----------
F-21
DEFERRED CREDITS AND OTHER LIABILITIES:
Unamortized investment credit ............... 65,823 18,199
Deferred income taxes ....................... 399,751 128,639
Adverse power purchase commitment ........... 185,626
Other ....................................... 25,843 3,403
----------- -----------
491,417 335,867
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTE L)
MEMBER'S EQUITY ............................... 759,643 512,699
----------- -----------
Total ......................................... $ 2,607,572 $ 1,375,506
=========== ===========
- ----------
See accompanying notes to the consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.
F-22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(THESE NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.)
NOTE A: NATURE OF OPERATIONS
Allegheny Energy Supply Company, LLC (the Company), a limited liability
company established under the laws of the state of Delaware, was formed in
November 1999. The Company is a wholly-owned subsidiary of Allegheny Energy, Inc
(Allegheny Energy). Allegheny Energy is a public utility holding company.
The Company was formed in order to consolidate Allegheny Energy's
deregulated energy supply business. On November 18, 1999, one of the Company's
affiliates, West Penn Power Company (West Penn), transferred its generating
capacity of 3,778 megawatts (MW) to the Company at net book value, as allowed by
the final settlement in West Penn's Pennsylvania restructuring case. West Penn
continued to be responsible for providing generation to meet the regulated
electric load of its retail customers who did not have the right to choose their
generation supplier until January 2, 2000. For the period from November 18,
1999, through January 1, 2000, the Company entered into a lease agreement with
West Penn with the unlimited right to use those facilities to serve its
regulated load. In 1999, the Company also purchased 276 MW of merchant capacity
at Fort Martin Unit No. 1 from another affiliate, AYP Energy, Inc. (AYP Energy).
In addition, on August 1, 2000, the Company's affiliate, The Potomac Edison
Company (Potomac Edison), transferred its generating assets, except certain
hydroelectric facilities located in Virginia, to the Company at net book value.
This transfer totaled approximately 2,100 MW of generating capacity.
Allegheny Generating Company (AGC) is a majority-owned subsidiary of the
Company. AGC owns and sells generating capacity to its parents, the Company and
Monongahela Power Company (Monongahela Power). As of December 31, 2000, the
Company and AGC have 6,270 MW of generating capacity and have an entitlement to
a portion of the generating capacity, 202 MW, of another facility partially
owned by Allegheny Energy.
The Company operates primarily in the mid-atlantic region as a single
unregulated segment marketing competitive wholesale electricity throughout the
eastern United States and retail electricity in states where customer choice has
been implemented, and operates regulated generation for its affiliates. In 2000,
91.3% of revenues were from bulk power sales to affiliates. The Company's
operations may be subject to federal regulation, but are not subject to state
regulation of rates.
NOTE B: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Certain amounts in the December 31, 1999, consolidated balance sheet and in
the December 31, 1999 consolidated statements of operations and cash flows for
the period ended December 31, 1999, have been reclassified for comparative
purposes.
The significant accounting policies of the Company and its subsidiary are
summarized below.
CONSOLIDATION
The asset transfers from West Penn and Potomac Edison (described in Note A)
included West Penn's 45% and Potomac Edison's 28% ownership of AGC. As a result
of the transfer, the Company's ownership of AGC increased from 45% as of July
31, 2000, to 73% as of August 1, 2000, with the remainder owned by Monongahela
Power. Through July 31, 2000, the Company utilized the equity method of
accounting for its investment in AGC. Effective August 1, 2000, the Company's
consolidated financial statements include the operations of AGC and the related
minority interest.
Prior to August 1, 2000, the Company reported a liability for an adverse
power purchase commitment for electric generation acquired from AGC. In
connection with the consolidation of AGC as of August 1, 2000 this adverse power
purchase commitment liability has been reclassified as a reduction in property,
plant, and equipment owned by AGC. This reclassification reflects the impairment
of AGC assets that was previously calculated. However, due to the fact AGC
assets were not previously consolidated in the Company's financial statements,
this was reported as an adverse purchase commitment.
F-23
The consolidated financial statements include the accounts of the Company
and its subsidiary company after elimination of intercompany transactions.
The Company has various operating transactions with its affiliates. It is
the Company's policy that the affiliated receivable and payable balances
outstanding from these transactions are presented net on the balance sheet.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates that affect
the reported amounts of assets, liabilities, revenues, expenses, and disclosures
of contingencies during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
REVENUES
Revenues from the sale of generation are recorded in the period the
electricity is delivered and consumed by customers. Revenues also include
amounts for recording the Company's energy trading contracts at their fair
values as of the balance sheet date.
PROPERTY, PLANT, AND EQUIPMENT
The Company's property, plant, and equipment are stated at original cost.
The transfer of the generating assets from West Penn and Potomac Edison and the
purchase of Fort Martin Unit No. 1 from AYP Energy were recorded at the
transferring affiliates' book values. The cost and accumulated depreciation of
property, plant, and equipment retired or otherwise disposed of are removed from
related accounts and included in the determination of the gain or loss on
disposition. At December 31, 2000, property, plant and equipment also includes
AGC's 40% undivided interest in the Bath County pumped-storage hydroelectric
station and its connecting transmission facilities. The cost of AGC depreciable
property units retired, plus removal costs less salvage, are charged to
accumulated depreciation.
The Company capitalizes the cost of software developed for internal use.
These costs are amortized on a straight line basis over the expected useful life
of the software beginning upon a project's completion.
CAPITALIZED INTEREST
The Company capitalizes interest costs in accordance with the Financial
Accounting Standards Board's (FASB) Statement of Financial Accounting Standards
(SFAS) No. 34, "Capitalizing Interest Costs." The interest capitalization rates
in 2000 and 1999 were 5.75% and 7.14%, respectively.
DEPRECIATION AND MAINTENANCE
Depreciation expense is determined generally on a straight-line method
based on estimated service lives of depreciable properties and amounted to
approximately 2.7% and 3.5% of annualized depreciable property in 2000 and 1999,
respectively. The cost of maintenance and of certain replacements of property,
plant, and equipment is charged principally to operating expenses when incurred.
Maintenance expenses represent costs incurred to maintain the power
stations, and reflect routine maintenance of equipment, as well as planned
repairs and unplanned expenditures, primarily from forced outages at the power
stations. Maintenance costs are expensed in the year incurred. Power station
maintenance costs are expensed within the year based on estimated annual costs
and estimated generation. Power station maintenance accruals are not intended to
accrue for future years' costs.
F-24
TEMPORARY CASH INVESTMENTS
For purposes of the consolidated statement of cash flows, temporary cash
investments with original maturities of three months or less, generally in the
form of commercial paper, certificates of deposit, and repurchase agreements,
are considered to be the equivalent of cash.
REGULATORY ASSETS AND LIABILITIES.
In accordance with SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation," the Company's financial statements include certain assets
and liabilities resulting from cost-based ratemaking regulation in connection
with AGC, a FERC-regulated subsidiary. Regulatory assets represent probable
future revenues associated with deferred costs that are expected to be recovered
from customers through the ratemaking process. Regulatory liabilities represent
probable future reductions in revenues associated with amounts that are to be
credited to customers through the ratemaking process. Regulatory liabilities,
net of regulatory assets were $16.5 million at December 31, 2000, and are
included in the consolidated balance sheet in deferred charges and other
deferred credits.
INCOME TAXES
The Company joins with its parent and affiliates in filing a consolidated
federal income tax return. The consolidated tax liability is allocated among the
participants generally in proportion to the taxable income of each participant,
except that no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from taxable income
principally because certain income and deductions for tax purposes are recorded
in the financial income statement in another period. Deferred tax assets and
liabilities represent the tax effect of temporary differences between the
financial statement and tax basis of assets and liabilities computed using the
most current tax rates.
The Company has deferred the tax benefit of investment tax credits, which
are amortized over the estimated service lives of the related properties.
POSTRETIREMENT BENEFITS
All of the employees of Allegheny Energy are employed by Allegheny Energy
Service Corporation (AESC), a wholly-owned subsidiary of Allegheny Energy, which
performs services at cost for the Company and its affiliates in accordance with
the PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 (PUHCA). Through AESC, the
Company is responsible for its proportionate share of postretirement benefit
costs. AESC provides a noncontributory defined benefit pension plan covering
substantially all employees, including officers. Benefits are based on the
employee's years of service and compensation. The funding policy is to
contribute annually at least the minimum amount required under the EMPLOYEE
RETIREMENT INCOME SECURITY ACT and not more than can be deducted for federal
income tax purposes. Plan assets consist of equity securities, fixed income
securities, short-term investments, and insurance contracts.
AESC also provides partially contributory medical and life insurance plans
for eligible retirees and dependents. Medical benefits, which make up the
largest component of the plans, are based upon an age and years-of-service
vesting schedule and other plan provisions. Subsidized medical coverage is not
provided in retirement to employees hired on or after January 1, 1993. The
funding policy is to contribute the maximum amount that can be deducted for
federal income tax purposes. Funding of these benefits is made primarily into
voluntary Employee Beneficiary Association trust funds. Medical benefits are
self-insured. The life insurance plan is paid through insurance premiums.
ENERGY TRADING ACTIVITIES
Based upon the Company's continual evaluation of its business activities
under the provisions of Emerging Issues Task Force (EITF) Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk
F-25
Management Activities," the Company concluded that its wholesale electricity
activities now represent trading activities. Accordingly, the Company recorded
its contracts entered into in connection with energy trading at fair value on
the balance sheet, with a net gain recorded on the statement of operations. See
Note K for additional information.
COMPREHENSIVE INCOME
SFAS No. 130, "Reporting Comprehensive Income," established standards for
reporting comprehensive income and its components (revenues and expenses) in the
financial statements. As of December 31, 2000, the Company does not have any
elements of other comprehensive income to report in accordance with SFAS No.
130.
NOTE C: INDUSTRY DEREGULATION
PENNSYLVANIA DEREGULATION
On August 1, 1997, West Penn filed with the Pennsylvania Public Utility
Commission (Pennsylvania PUC) a comprehensive restructuring plan to implement
full customer choice of electricity suppliers as required by the CUSTOMER CHOICE
ACT. The filing included a plan for recovery of transition costs through a
Competitive Transition Charge (CTC). On May 29, 1998 (as amended on November 19,
1998), the Pennsylvania PUC granted final approval to West Penn's restructuring
plan, which included the following provisions:
o Provided two-thirds of West Penn's customers the option of selecting a
generation supplier on January 2, 1999, with all customers able to shop
on January 2, 2000.
o Authorized the transfer of West Penn's generating assets to the Company
at book value. Subject to certain time-limited exceptions, the Company
can compete in the unregulated energy market in Pennsylvania. As
described in Note D, this transfer occurred on November 18, 1999.
MARYLAND DEREGULATION
On September 23, 1999, Potomac Edison filed a settlement agreement
(covering its stranded cost quantification mechanism, price protection
mechanism, and unbundled rates) with the Maryland Public Service Commission
(Maryland PSC). All parties active in the case, except Eastalco, which stated
that it would not oppose it, signed the agreement. The settlement agreement,
which was approved by the Maryland PSC on December 23, 1999, includes the
following provisions:
o The ability for nearly all of Potomac Edison's approximately 210,000
Maryland customers to have the option of choosing an electric generation
supplier starting July 1, 2000.
o The transfer of Potomac Edison's Maryland jurisdictional generating
assets to the Company at book value on or after July 1, 2000. As
described in Note D, this transfer occurred on August 1, 2000.
VIRGINIA DEREGULATION
On May 25, 2000, Potomac Edison filed an application with the Virginia
State Corporation Commission (Virginia SCC) to separate its approximately 380 MW
of generating assets, excluding the hydroelectric assets located within the
state of Virginia, from its transmission and distribution (T&D) assets,
effective July 1, 2000. On July 11, 2000, the Virginia SCC issued an order
approving Potomac Edison's separation plan permitting the transfer of its
Virginia jurisdictional generating assets to the Company. As described in Note
D, this transfer occurred on August 1, 2000.
WEST VIRGINIA DEREGULATION
The West Virginia Legislature passed House Concurrent Resolution 27 on
March 11, 2000, approving an electric deregulation plan submitted by the Public
Service Commission of West Virginia (W.Va. PSC) with certain
F-26
modifications. Further action by the Legislature, including the enactment of
certain tax changes regarding preservation of tax revenues for state and local
government, is required prior to the implementation of the restructuring plan
for customer choice. The Company expects that implementation of the deregulation
plan will occur if the Legislature approves the necessary tax law changes. Among
the provisions of the plan are the following:
o Customer choice will begin for all customers when the plan is
implemented.
o The Company's affiliate, Monongahela Power, is permitted to file a
petition seeking W.Va. PSC Approval to transfer the West Virginia
jurisdictional generating assets and capacity entitlements
(approximately 2,083 MW) to the Company at book value. Also, based on a
final order issued by the W. Va. PSC on June 23, 2000, the West Virginia
jurisdictional generating assets of Potomac Edison were transferred to
the Company at book value in August 2000, in conjunction with the
Maryland law that allows generating assets to be transferred to
non-regulated ownership.
OHIO DEREGULATION
On October 5, 2000, the Public Utilities Commission of Ohio (Ohio PUC)
approved a settlement to implement a restructuring plan for Monongahela Power.
The plan will allow Monongahela Power's 29,000 Ohio customers to choose their
electricity supplier starting in January 2001. Highlights of the plan include
the following:
o Monongahela Power is permitted to transfer approximately 351 MW of
Ohio/FERC jurisdictional generating assets to the Company at net book
value on or after January 1, 2001.
o The Company will be permitted to offer competitive generation service
throughout Ohio.
NOTE D: TRANSFER OF ASSETS
Pursuant to the various commission settlements approved resulting from
industry restructuring as described in Note C, West Penn in 1999, and Potomac
Edison in 2000, transferred their generating capacity to the Company at book
value. In 1999 the Company also purchased 276 MW of generating capacity from AYP
Energy. The net effect of the assets transferred to the Company are shown below:
POTOMAC WEST AYP
EDISON PENN ENERGY TOTAL
------ -------- ------ --------
(millions of dollars)
Property, plant, and equipment,
net of accumulated depreciation ...... $446.5 $ 920.3 $152.7 $1,519.5
Investment in AGC ...................... 42.3 71.5 -- 113.8
Other assets ........................... 33.2 120.6 25.9 179.7
------ -------- ------ --------
Total Assets ......................... $522.0 $1,112.4 $178.6 $1,813.0
====== ======== ====== ========
Member's equity ........................ $227.5 $ 465.4 $ 35.2 $ 728.1
Long-term debt ......................... 183.8 230.6 130.0 544.4
Other liabilities ...................... 110.7 416.4 13.4 540.5
------ -------- ------ --------
Total Liabilities & Member's Equity .... $522.0 $1,112.4 $178.6 $1,813.0
====== ======== ====== ========
The total changes in member's equity for the non-cash transfers were $233.8
million and $494.3 million in 2000 and 1999, respectively.
NOTE E: INCOME TAXES
Details of federal and state income tax provisions are:
2000 1999
-------- -------
(thousands of dollars)
Income taxes -- current:
Federal ......................................... $ 24,655 $ 3,370
State ........................................... 4,686 1,288
-------- -------
Total ......................................... 29,341 4,658
Income taxes-deferred, net of amortization ........ 9,206 (2,001)
Amortization of deferred investment credit ........ (2,466) (153)
-------- -------
Total income taxes ................................ $ 36,081 $ 2,504
======== =======
F-27
The total provision for income taxes is different from the amount produced
by applying the federal income statutory tax rate of 35% to financial accounting
income, as set forth below:
2000 1999
--------- ---------
(thousands of dollars)
Income before income taxes and minority interest ... $ 114,077 $ 12,036
--------- ---------
Amount so produced ................................. 39,927 4,213
Increased (decreased) for:
Tax deductions for which deferred tax
was not provided Lower tax depreciation ........ 380
State income tax benefit, net of federal
income tax benefit ............................. 3,577 647
Amortization of deferred investment credit ....... (2,466) (153)
Amortization of deferred income taxes ............ (1,353)
Equity in earnings of subsidiaries ............... (2,395) (412)
Other, net ....................................... (2,942) (438)
--------- ---------
Total .......................................... $ 36,081 $ 2,504
========= =========
At December 31, the deferred tax assets and
liabilities consisted of the following:
2000 1999
--------- ---------
(thousands of dollars)
DEFERRED TAX ASSETS:
Adverse power purchase commitment ................ $ 86,436
Investment tax credit ............................ $ 30,911
Impaired asset ................................... 11,852
Tax interest capitalized ......................... 17,657 10,940
Recovery of transition costs ..................... 5,554 5,554
Reserve for uncollectibles ....................... 2,341 465
Postretirement benefits other than pensions ...... 3,188 63
Other ............................................ 2,098 3,350
--------- ---------
73,601 106,808
--------- ---------
DEFERRED TAX LIABILITIES:
Book vs. tax plant basis differences, net ........ 451,029 224,934
Other ............................................ 10,416 46
--------- ---------
461,445 224,980
--------- ---------
Total net deferred tax liabilities ................. 387,844 118,172
Portion above included in current assets ........... 11,907 10,467
--------- ---------
Total long-term net deferred tax liabilities ... $ 399,751 $ 128,639
========= =========
NOTE F: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
As described in Note B, the Company is responsible for its proportionate
share of the cost of the pension plan and medical and life insurance plans for
eligible employees and dependents provided by AESC. The Company's share of the
costs of these plans, a portion of which was charged or credited to plant
construction, is as follows:
2000 1999
--------- ---------
(thousands of dollars)
Pension ............................................ ($ 447) $ 65
Medical and life insurance ......................... $1,888 $ 154
F-28
NOTE G: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at
December 31 were as follows:
2000 1999
-------------------- --------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(thousands of dollars)
ASSETS:
Temporary cash investments ... $ 90 $ 90 $ 100 $ 100
LIABILITIES:
Short-term debt .............. $219,015 $219,015 $ 21,200 $ 21,200
Long-term debt ............... $563,433 $553,113 $360,815 $349,359
The carrying amount of temporary cash investments, as well as short-term
debt, approximates the fair value because of the short maturity of those
instruments. The fair value of long-term debt was estimated based on actual
market prices or market prices of similar issues.
NOTE H: CAPITALIZATION
MEMBER'S EQUITY:
Member's equity includes member's capital contributions for Potomac Edison,
West Penn, and AYP Energy asset transfers as described in Note D. The remaining
increases were additional capital contributions from
F-29
Allegheny Energy of $26.9 million and $12.3 million in 2000 and 1999,
respectively. The return of member's capital contribution relates primarily to a
note receivable assigned to Allegheny Energy, the parent.
LONG-TERM DEBT:
The Company had long-term debt outstanding as follows:
DECEMBER 31, 2000 DECEMBER 31, 1999
-------------------- --------------------
INTEREST INTEREST
RATE -- % AMOUNT RATE -- % AMOUNT
---------- -------- ---------- --------
(thousands of dollars)
Secured notes due 2003-2029 ...... 4.70-6.875 $317,379 4.70-6.875 $216,380
Unsecured notes due 2002-2007 .... 4.35-4.75 17,635 4.75 14,435
Debentures due 2003-2023 ......... 5.625-6.875 150,000
Medium-term debt due 2001-2002 ... 7.559 80,000 6.46125 130,000
Unamortized debt discount
and premium, net ............... (1,581)
-------- --------
Subtotal ......................... 563,433 360,815
Less amounts on deposit
with trustees .................. (4,576)
-------- --------
Total ............................ $563,433 $356,239
======== ========
The service obligation for the secured and unsecured notes (pollution
control debt) was assumed by the Company in conjunction with the transfer of
Potomac Edison's and West Penn's generating assets to the Company. The
debentures relate to AGC borrowings which are consolidated with the Company as
of August 1, 2000. The interest rate for the $130 million medium-term debt in
1999 was priced at the London Interbank Offer Rate (LIBOR) plus a spread and was
reset quarterly. This debt was refinanced in October 2000 with short term debt.
Maturities for long-term debt in thousands of dollars for the next five
years are: 2001, none; 2002, $83,200; 2003, $111,500; 2004, none; and 2005,
none. Some properties are also subject to a second lien securing certain
pollution control and solid waste disposal notes.
On June 1, 2000, Potomac Edison issued $80 million floating rate private
placement notes, due May 1, 2002, assumable by the Company upon its acquisition
of Potomac Edison's Maryland electric generating assets. In August 2000, after
the Potomac Edison generating assets were transferred to the Company, the notes
were remarketed as the Company's floating rate (three-month LIBOR plus .80%)
notes with the same maturity date. No additional proceeds were received.
NOTE I: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial paper,
lines of credit have been established with several banks. The Company has fee
arrangements on all of its lines of credit and no compensating balances
requirements. At December 31, 2000, unused lines of credit with banks were
$180.0 million. In addition to bank lines of credit, an Allegheny Energy
internal money pool accommodates intercompany short-term borrowing needs of the
Company, to the extent that affiliates have funds available.
F-30
Short-term debt outstanding for 2000 and 1999 consisted of:
2000 1999
-------------- -------------
(thousands of dollars)
BALANCE AND INTEREST RATE AT END OF YEAR:
Money pool ................................ $ 53,250-6.45% $21,200-4.85%
Commercial paper .......................... $165,765-7.16%
AVERAGE AMOUNT OUTSTANDING AND INTEREST
RATE DURING THE PERIOD:
Money pool ................................ $ 49,861-6.17% $16,702-5.50%
Commercial paper .......................... $ 84,729-6.68%
NOTE J: RELATED PARTY TRANSACTION
The Company supplies electricity to its regulated utility affiliates in
accordance with agreements approved by the Federal Energy Regulatory Commission
(FERC), including electricity supplied to West Penn and Potomac Edison to meet
their retail load requirements as the default provider during the transition
period for deregulation plans approved in Pennsylvania and Maryland. The revenue
from these sales is reported separately on the consolidated statement of
operations as " Operating Revenue -- affiliated".
During 2000 and 1999, the Company recorded $10.0 million and $3.7 million,
respectively, of competitive transition charge (CTC) revenue related to West
Penn's deregulation plan approved by the Pennsylvania PUC. The Pennsylvania PUC
authorized West Penn to collect from its customers CTC revenue to recover
transition costs, including certain costs of generating assets. Since West
Penn's generating assets were transferred to the Company in November 1999, the
related CTC revenue was also transferred to the Company since November 1999.
All of the employees of Allegheny Energy are employed by AESC, which
performs services at cost for the Company and its affiliates in accordance with
the PUHCA. Through AESC, the Company is responsible for its proportionate share
of services provided by AESC. The total billings by AESC (including capital) to
the Company in 2000 and 1999 were $95.3 million and $12.4 million, respectively.
In conjunction with the transfer of the generating assets of West Penn and
Potomac Edison to the Company, the Company assumed $335.0 million of pollution
control debt. West Penn is a guarantor of $230.8 million and Potomac Edison is a
guarantor of $104.2 million of this pollution control debt, at December 31,
2000.
The transfer of Potomac Edison's generating assets to the Company, on
August 1, 2000, included the Potomac Edison assets located in West Virginia. The
West Virginia portion of these assets have been leased back to Potomac Edison to
serve the West Virginia jurisdictional retail customers. Affiliated revenue in
2000 includes $37.1 million for this rental income. The lease term is one year,
but may be modified upon mutual agreement of both parties to the lease. The
ultimate treatment of the West Virginia portion of the generating assets
transferred from Potomac Edison will be resolved when the West Virginia
legislature addresses the implementation of deregulation.
Certain generating assets are owned jointly by the Company and its
affiliate, Monongahela Power, as tenants in common. The assets are operated by
the Company, with each of the owners being entitled to the available energy
output and capacity in proportion to its ownership in the assets. Monongahela
Power does the billing for the jointly owned stations located in West Virginia,
while the Company is responsible for billing Hatfield's Ferry Power Station, a
Pennsylvania station. In 2000, the Company's share of the cost of the West
Virginia stations was $400.3 million and Monongahela Power's share of Hatfield's
Ferry Power Station costs was $38.4 million.
F-31
NOTE K: ENERGY TRADING ACTIVITIES
TRADING OPERATIONS
The Company enters into contracts for the purchase and sale of electricity
in the wholesale market. The Company's wholesale market activities consist of
buying and selling over-the-counter contracts for the purchase and sale of
electricity. The majority of these are forward contracts representing
commitments to purchase and sell at fixed prices in the future. These contracts
require physical delivery. The Company also uses option contracts to buy and
sell electricity at fixed prices in the future.
During 2000, the Company substantially increased the volume of its
wholesale electricity trading activities due to the completion of the
construction or acquisition of additional generating capacity. The Company also
anticipates the expansion of additional generating capacity through construction
and acquisition activities in future years as a result of announcements made in
the fourth quarter of 2000. Based upon the Company's continual evaluation of its
business activities under the provisions of EITF Issue No. 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities," the
Company concluded that its wholesale electricity activities now represent
trading activities. EITF Issue 98-10 requires contracts entered into in
connection with energy trading to be marked to fair value on the balance sheet,
with all changes in fair value recorded as gains and losses on the statement of
operations. Accordingly, in the fourth quarter of 2000, the Company recorded its
wholesale energy contracts at fair value on the consolidated balance sheet at
December 31, 2000.
The wholesale electricity trading contracts representing an unrealized gain
position are reported as "Commodity Contract" assets in the current assets
section of the balance sheet. The wholesale electricity trading contracts
representing an unrealized loss position are reported as "Commodity Contract"
liabilities in the current liabilities section of the balance sheet. At December
31, 2000, the fair value of the "Commodity Contracts" assets and liabilities
related to wholesale electricity trading activities was $234.5 million and
$224.6 million, respectively. A net gain of $8.4 million, before tax, was
recorded to the statement of operations, as part of wholesale operating
revenues, to reflect the fair value of the Company's energy trading contracts.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 133 was subsequently amended by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities-- Deferral of the
Effective Date of FASB Statement No. 133-- an amendment of FASB Statement No.
133" and SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities-- an amendment of FASB Statement No. 133." Effective
January 1, 2001, the Company will implement the requirements of these accounting
standards.
These Statements establish accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, collectively referred to as derivatives, and for hedging
activities. They require that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. The Statements require that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement or other comprehensive income, and requires that a
company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133 is expected to increase
the volatility in reported earnings and other comprehensive income.
The Company has completed an inventory of financial instruments, commodity
contracts, and other commitments for the purpose of identifying and assessing
all of our derivatives. The Company determined the fair value of the
derivatives, designated certain derivatives as hedges, and assessed the
effectiveness of those derivatives as hedges.
F-32
The Company will record an asset of $1.5 million on the 2001 balance sheet
based on the fair value of the two cash flow hedge contracts at January 1, 2001.
An offsetting amount will be recorded in other comprehensive income as a change
in accounting principle as provided by SFAS No. 133. The Company anticipates
that the amounts accumulated in other comprehensive income related to these
contracts will be reclassified to earnings during July and August of 2001 when
the hedged transactions are recorded.
The Company will also record certain option contracts that meet the
derivative criteria in SFAS No. 133, which do not qualify for special hedge
accounting. The Company will record an asset of $0.1 million and a liability of
$52.4 million on its balance sheet based on the fair value of these contracts at
January 1, 2001. The majority of this liability related to one contract. The
fair value of this contract represented a liability of approximately $52.3
million on January 1, 2001. The liability associated with this contract will
reduce to zero at December 31, 2001, with the expiration of the contract. The
fair value of these contracts will fluctuate over time due to changes in the
underlying commodity prices that are influenced by various market factors,
including the weather and availability of regional electric generation and
transmission capacity. In accordance with SFAS No. 133, the Company will record
a charge of $31.2 million against earnings net of the related tax effect ($52.3
million before tax) in the first quarter of 2001 for these contracts as a change
in accounting principle as of January 1, 2001.
NOTE L: COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
The Company has entered into commitments for its construction and capital
programs for which expenditures are estimated to be $1,947 million for 2001 and
$313 million for 2002. These estimates exclude expenditures related to the
Monongahela Power West Virginia generating assets, which will be transferred to
the Company after receiving final approval from the West Virginia PSC and the
Securities and Exchange Commission (SEC). Construction expenditure levels in
2003 and beyond will depend upon, among other things, the strategy eventually
selected for complying with Phase II of the CLEAN AIR ACT AMENDMENTS OF 1990
(CAAA) and the extent to which environmental initiatives currently being
considered become mandated. The Company estimates that its management of
emission allowances will allow it to comply with Phase II sulfur dioxide (SO2)
limits through 2005. Studies to evaluate cost-effective options to comply with
Phase II SO2 limits beyond 2005, including those available in connection with
the emission allowance trading market, are continuing.
The Company has announced the construction and acquisition of various
generating facilities planned for completion in 2001 through 2005. Also, the
Company has announced the acquisition of Merrill Lynch's energy trading and
commodity marketing unit (see Note M). The estimated cost of generating
facilities under construction and acquisitions announced by the Company is
approximately $3.0 billion.
On November 14, 2000, the Company announced the acquisition of three
natural gas-fired merchant generating facilities totaling 1,710 MW located in
the Midwest from Enron North America (Enron). The completion of the transaction
requires certain regulatory approvals, including approval by the SEC. The
agreement between Enron and Allegheny Energy requires that the parties close on
the transaction prior to May 31, 2001. In the event that closing does not occur
prior to May 31, 2001, because SEC approval has not been obtained, the Company
would be required to pay a termination fee of approximately $41 million to
Enron.
ENVIRONMENTAL MATTERS AND LITIGATION
The Company is subject to various laws, regulations, and uncertainties as
to environmental matters. Compliance may require the Company to incur
substantial additional costs to modify or replace existing and proposed
equipment and facilities and may adversely affect the cost of future operations.
The Environmental Protection Agency's (EPA) nitrogen oxides (NOX) STATE
IMPLEMENTATION PLAN (SIP) call regulation has been under litigation and on March
3, 2000, the District of Columbia Circuit Court of Appeals issued a decision
that upheld the regulation. However, state and industry litigants filed an
appeal of that decision in April 2000. On June 23, 2000, the Court denied the
request for the appeal. Although the Court did issue an order to delay the
compliance date from May 1, 2003 until May 31, 2004, both the Maryland and
Pennsylvania
F-33
state rules to implement the EPA NOx SIP call regulation still require
compliance by May 1, 2003. West Virginia has issued a proposed rule that would
postpone compliance until May 1, 2005. However, the EPA Section 126 petition
regulation also requires the same level of NOX reductions as the EPA NOX SIP
call regulation with a May 1, 2003, compliance date. The EPA Section 126
petition rule is also under litigation in the District of Columbia Circuit Court
of Appeals, with a decision expected by early 2001. The Company's compliance
with such stringent regulations will require the installation of expensive
post-combustion control technologies on most of its power stations. The
Company's construction forecast includes the expenditure of approximately $440
million in total capital costs through 2004 to comply with these regulations, or
$339 million excluding expenditures related to the Monongahela Power West
Virginia jurisdictional generating assets to be transferred. Approximately $46.7
million was spent in 2000.
On August 2, 2000, Allegheny Energy received a letter from the EPA
requiring it to provide certain information on 10 of its electric generating
stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry,
Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. The Company
is a joint-owner with an affiliate, Monongahela Power, in five of these stations
and is the sole owner of two others. The letter requested information under
Section 114 of the federal CLEAN AIR ACT to determine compliance with federal
CLEAN AIR ACT and state implementation plan requirements, including potential
application of federal New Source Performance Standards. In general, such
standards can require the installation of additional air pollution control
equipment upon the major modification of an existing facility. The Company
submitted these records in January 2001. The eventual outcome of the EPA
investigation is unknown.
Similar inquiries have been made of other electric utilities and have
resulted in enforcement proceedings being brought in many cases. The Company
believes its generating facilities have been operating in accordance with the
CLEAN AIR ACT and the rules implementing the Act. The experience of other
utilities, however, suggests that, in recent years, the EPA may well have
revised its interpretation of the rules regarding the determination of whether
an action at a facility constitutes routine maintenance, which would not trigger
the requirements of the New Source Performance Standards, or a major
modification of the facility, which would require compliance with the New Source
Performance Standards. If federal New Source Performance Standards were to be
applied to these generating stations, in addition to the possible imposition of
fines, compliance would entail significant expenditures.
In December 2000, the EPA issued a decision to regulate coal-fired and
oil-fired electric utility mercury emissions under Title III, Section 112 of the
1990 CLEAN AIR ACT AMENDMENTS. The EPA plans to issue a proposed regulation by
December 2003 and a final regulation by December 2004. The timing and level of
required mercury emission reductions are unknown at this time.
The Attorney General of the State of New York and the Attorney General of
the State of Connecticut in their letters dated September 15, 1999, and November
3, 1999, respectively, notified Allegheny Energy of their intent to commence
civil actions against Allegheny Energy or certain of its subsidiaries alleging
violations at the Fort Martin Power Station under the federal CLEAN AIR ACT,
which requires existing power plants that make major modifications to comply
with the same emission standards applicable to new power plants. Other
governmental authorities may commence similar actions in the future. Fort Martin
is a station located in West Virginia and is now jointly owned by the Company
and Monongahela Power. Both Attorneys General stated their intent to seek
injunctive relief and penalties. In addition, the Attorney General of the State
of New York in his letter indicated that he may assert claims under the State
common law of public nuisance seeking to recover, among other things,
compensation for alleged environmental damage caused in New York by the
operation of Fort Martin Power Station. At this time, the Company is not able to
determine what effect, if any, these actions threatened by the Attorneys General
of New York and Connecticut may have on them.
In the normal course of business, the Company and its subsidiary become
involved in various legal proceedings. The Company and its subsidiary do not
believe that the ultimate outcome of these proceedings will have a material
effect on their financial position.
LEASES
The Company has multiple operating lease agreements with various terms and
expiration dates, primarily for office space, computer equipment, and office
furniture. Total operating lease rent payments of $6.5 million and $1.2
F-34
million were recorded as rent expense in 2000 and 1999, respectively. Estimate
minimum lease payments for operating leases with initial or remaining terms in
excess of one year are $3.1 million in 2001, $2.1 million in 2002, $9.3 million
in 2003, $24.3 million in 2004, $22.1 million in 2005, and $8.2 million
thereafter.
In November 2000, the Company consummated an operating lease transaction
relating to the construction of a 540 MW combined-cycle generating plant located
in Springdale, Pennsylvania. This transaction was structured to finance the
construction of the plant with a maximum commitment amount of $318.4 million.
Upon completion of the plant, a special purpose entity will lease the plant to
the Company. Lease payments, to be recorded as rent expense, are estimated at
$1.9 million per month, commencing during the second half of 2003 through 2005.
Subsequently, the Company has the right to negotiate up to two five-year renewal
terms or purchase the plant for the lessor's investment or sell the plant and
pay the difference between the proceeds and the lessor's investment up to a
maximum recourse amount of approximately $275 million.
The transfer of Potomac Edison's generating assets to the Company, on
August 1, 2000, included the Potomac Edison assets located in West Virginia. The
West Virginia portion of these assets have been leased back to Potomac Edison to
serve the West Virginia jurisdictional retail customers. Affiliated revenue in
2000 includes $37.1 million for this rental income. The lease term is one year,
but may be modified upon mutual agreement of both parties to the lease.
FUEL PURCHASE COMMITMENTS
The Company has entered into various long-term commitments for the
procurement of fuels, primarily coal, to supply its generating plants. In most
cases, these contracts contain provisions for price escalations, minimum
purchase levels, and other financial commitments. The Company purchased $317.2
million and $18.1 million in 2000 and 1999, respectively. In 2000, the Company
purchased approximately 60% of its fuel from one vendor. Total estimated
long-term minimum fuel obligations at December 31, 2000, for the next five years
(excluding amounts related to the Monongahela Power generating assets that we
expect to have transferred to us) were as follows:
(millions of dollars)
YEAR AMOUNT
---- -------
2001 ............................. $144.2
2002 ............................. $123.1
2003 ............................. $ 97.0
2004 ............................. $ 93.9
2005 ............................. $ 71.9
------
Total commitments ................ $530.1
======
LETTER OF CREDIT
A letter of credit is a purchased guarantee that ensures the Company's
performance or payment to third parties, in accordance with certain terms and
conditions. The Company has a letter of credit which amounted to $750,000 as of
December 31, 2000.
NOTE M: SUBSEQUENT EVENTS
On January 8, 2001, Allegheny Energy announced that the Company had signed
a definitive agreement to acquire the Energy Trading Business from Merrill
Lynch. Under the agreement, the Company will acquire the Energy Trading Business
by paying Merrill Lynch $490 million, plus a 2% equity interest in the Company.
The acquisition is contingent upon regulatory approvals, including approvals of
FERC and the Department of Justice/Federal Trade Commission. The Company expects
that the transaction can be completed in the first quarter of 2001.
F-35
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(thousands of dollars)
CONSOLIDATED
INCOME BEFORE
INCOME TAXES
OPERATING OPERATING OPERATING AND MINORITY NET
QUARTER ENDED REVENUES EXPENSES INCOME INTEREST INCOME
- ------------- --------- --------- --------- ------------- -------
December 1999* ..... $140,874 $127,904 $12,970 $12,036 $ 9,532
March 2000 ......... 376,020 343,947 32,073 27,571 18,155
June 2000 .......... 410,350 394,796 15,554 12,104 9,949
September 2000** ... 689,229 657,114 32,115 23,042 14,759
December 2000** .... 783,973 719,722 64,251 51,360 32,625
- ----------
* Results for the quarter ended December 1999 are for the period November 18,
1999, to December 31, 1999.
** Includes earnings associated with assets transferred on August 1, 2000,
from Potomac Edison.
F-36
REPORT OF INDEPENDENT ACCOUNTANTS
To Allegheny Energy, Inc., the Sole Member of Allegheny Energy Supply Company,
LLC:
We have audited the accompanying statement of assets acquired and liabilities
assumed of Global Energy Markets, a unit of Merrill Lynch Capital Services, (the
"Company") at December 29, 2000 and the related statement of revenues and direct
expenses for the year then ended (the "carve-out financial statements"). These
carve-out financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these carve-out
financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the carve-out
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the carve-out financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall presentation of the carve-out financial statements. We
believe that our audit provides a reasonable basis for our opinion.
The accompanying carve-out financial statements were prepared for the purpose of
complying with the rules and regulations of the Securities and Exchange
Commission as described in Note 2 and are not intended to be a complete
presentation of the Company's financial position or results of operations.
In our opinion, the carve-out financial statements referred to above present
fairly, in all material respects, the financial position of the Company at
December 29, 2000, and the results of its operations for the year then ended in
conformity with accounting principles generally accepted in the United States of
America.
PricewaterhouseCoopers LLP
New York, New York
December 20, 2001
F-37
Global Energy Markets
Statement of Revenues and Direct Expenses
Of Business Purchased on March 16, 2001
by Allegheny Energy Supply Company, LLC
(Thousands of Dollars)
Year Ended
December 29,
2000
----
REVENUES
Net trading revenues $33,477
-------
DIRECT EXPENSES
General and administrative 1,309
Other Operations 14,536
-------
Total Direct Expenses 15,845
-------
EXCESS OF REVENUES OVER
DIRECT EXPENSES $17,632
=======
See accompanying notes to financial statements.
F-38
Global Energy Markets
Statement of Assets Acquired and Liabilities Assumed
Of Business Purchased on March 16, 2001
by Allegheny Energy Supply Company, LLC
(Thousands of Dollars)
As of
December 29,
2000
----
ASSETS ACQUIRED
Assets
Cash margin account $ 7,703
Commodity and other
trading contracts 701,260
NYMEX exchange seats
1,300
---------
Total Assets Acquired $ 710,263
=========
LIABILITIES ASSUMED
Liabilities
Commodity and other
trading contracts $ 586,681
---------
Total Liabilities $ 586,681
---------
Assumed
NET ASSETS ACQUIRED $ 123,582
=========
See accompanying notes to financial statements.
F-39
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
(These notes are an integral part of the financial statements.)
1. ORGANIZATION AND OPERATIONS
Global Energy Markets (the "Energy Trading Business") was formed in 1999 as an
energy commodity marketing and trading unit of Merrill Lynch Capital Services,
Inc. which is a direct wholly-owned subsidiary of Merrill Lynch & Co., Inc.
("Merrill Lynch"). The Energy Trading Business provides energy trading,
marketing, and risk management services to wholesale customers in North America.
On March 16, 2001, Allegheny Energy Supply Company, LLC (Allegheny Energy
Supply) purchased the Energy Trading Business from Merrill Lynch.
2. FINANCIAL STATEMENTS BASIS OF PRESENTATION
The financial statements presented represent carve-out financial statements of
the Energy Trading Business from the consolidated financial statements of
Merrill Lynch. The carve-out financial statements present the assets and
liabilities as of December 29, 2000, that were subsequently acquired by
Allegheny Energy Supply and the related revenues and direct expenses of the
Energy Trading Business for the year 2000 based on the historical accounting
records of Merrill Lynch. It is not practicable to provide a separate statement
of cash flows for the Energy Trading Business.
The Statement of Revenues and Direct Expenses represents revenues and direct
expenses for the year ended December 29, 2000, of the business subsequently
acquired by Allegheny Energy Supply. The revenues reflect amounts attributable
to the Energy Trading Business from energy trading contracts included in the
business acquired by Allegheny Energy Supply. Operations expenses include all
direct costs of the acquired trading business, of which the most significant is
compensation and benefits, including incentive compensation. Other direct costs
include occupancy of office buildings allocated to the Energy Trading Business
by Merrill Lynch based on office space occupied by the business, charges from
Merrill Lynch for use of computer systems and software, including an allocated
share of data center costs, charges from Merrill Lynch for use of communications
equipment and telephone charges, cost of subscriptions and fees for information
on energy markets and other information sources, fees for legal and other
professional services, travel costs, and other direct expenses charged to the
Energy Trading Business by Merrill Lynch (see Note 9 regarding related parties).
Merrill Lynch did not allocate other indirect general and administrative
expenses to the Energy Trading Business.
The accompanying financial statements were prepared for the purpose of complying
with the rules and regulations of the Securities and Exchange Commission and
are not intended to be a complete presentation of the Energy Trading Business's
financial position or results of operations.
These financial statements are not indicative of the financial condition or
results of operations of the business acquired by Allegheny Energy Supply going
forward since the Energy Trading Business's energy commodity marketing and
trading unit has been combined with the unregulated power generation portfolio
owned by Allegheny Energy Supply. The financial statements also omit various
operating expenses not directly involved in revenue-producing activities such as
corporate overhead, interest, and taxes.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues, expenses, and
disclosures of contingencies during the reporting period, which, in the normal
course of business, are subsequently adjusted to actual results. The use of
estimates is particularly applicable to the determination of the fair value of
energy commodity contracts including instruments that do not have quoted liquid
market prices. These estimates involve judgment with respect to, among other
things, various future economic factors that are difficult to predict and are
beyond the control of the Energy Trading Business. Therefore, actual results
could materially differ from those estimates and have a material impact on the
financial statements.
COMMODITY TRADING ACTIVITIES
The Energy Trading Business activities include the marketing and trading of
electricity, natural gas, and other energy commodities using primarily
over-the-counter contracts and New York Mercantile Exchange (NYMEX)
exchange-traded contracts.
F-40
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
The Energy Trading Business enters into physical energy commodities contracts
(physicals) and energy-related financial contracts. The physical energy
commodities contracts, which require physical delivery, include commitments for
the purchase or sale of energy commodities in current and future periods. The
energy-related financial contracts, which are normally settled as financial
transactions, include exchange-traded options, swap agreements, and certain
other contractual arrangements. These contracts, entered into in connection with
energy trading activities, are recorded at fair value on the balance sheet, with
all changes in fair value recorded as gains and losses on the statement of
operations. Accordingly, the Energy Trading Business records its energy trading
contracts as assets and liabilities at fair value on the Statement of Assets
Acquired and Liabilities Assumed with changes in fair value reported as net
trading revenue on the Statement of Revenues and Direct Expenses.
The fair value of energy commodity contracts which represent the net unrealized
gains and losses position are recorded as assets or liabilities, respectively,
after applying the appropriate counterparty netting agreements in accordance
with Financial Accounting Standards Board Interpretation No. 39 (FASB
Interpretation No. 39). At December 29, 2000, the fair value of the Commodity
Contract assets and liabilities were $701.3 million and $586.7 million,
respectively.
Fair values for exchange-traded instruments, principally futures and certain
options, are based on quoted market prices. The fair value of options includes
premium payments/receipts. For instruments that do not have quoted market
prices, primarily physical contracts, over-the-counter options, and swaps,
management uses available market data and pricing models to estimate fair
values. Estimating fair values of instruments which do not have quoted market
prices requires management judgment in determining amounts which could
reasonably be expected to be received from, or paid to, a third party in
settlement of the instruments. These amounts could be materially different from
amounts that might be realized in an actual sale transaction. Fair values are
subject to change in the near term and reflect management's best estimate based
on various factors including observable market transactions and third party
price quotations for comparable instruments, interest rates, volatilities,
durations, correlations, liquidity, and counterparty credit risk (see Note 5 for
additional information of trading activities).
REVENUES
Net trading revenues consist of unrealized amounts resulting from the change in
the fair value of energy trading contracts and for the amounts realized in the
settlement of commodity contracts at maturity. The Energy Trading Business
recorded all transactions related to its trading contracts on a net basis as a
component of revenue based on the accounting policies of Merrill Lynch. The net
revenues presented in the financial statements exclude amounts from certain
trading positions that Allegheny Energy Supply did not purchase from Merrill
Lynch.
CASH MARGIN ACCOUNT
The cash margin account represents cash on deposit with the NYMEX futures
exchange as collateral used for energy trading activities and recently settled
futures contracts.
NYMEX Exchange Seats
The NYMEX exchange seats are carried at historical cost in the Statement of
Assets Acquired and Liabilities Assumed.
F-41
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The cash margin account is carried at fair value in the Statement of Assets
Acquired and Liabilities Assumed. At December 29, 2000, the Energy Trading
Business had $7.7 million in the NYMEX cash margin account.
Trading commodity assets and liabilities are carried at fair value in accordance
with the Energy Trading Business's accounting policy described in Note 3. The
gross fair value of trading assets and liabilities, prior to applying the
appropriate counterparty netting agreements in accordance with FASB
Interpretation No. 39, including the spark spread option, as discussed below in
Note 5, as of December 29, 2000 are as follows:
December 29, 2000
Fair Value
----------
(Thousands of Dollars)
Assets Liabilities
------ -----------
Options $1,073,231 $ 691,418
Physicals 2,361,039 2,652,134
Energy Swaps 382,899 339,477
Interest Rate Swaps 19,561
---------- ----------
Total $3,817,169 $3,702,590
========== ==========
The payables and receivables resulting from the settlement or delivery of energy
contracts are recorded as assets or liabilities based on the counterparty's
position, giving effect to credit netting arrangements where appropriate. The
average fair value of trading assets and liabilities held during 2000 calculated
using month-end balances were $222.0 million and $180.3 million, respectively.
The average assets and liabilities were calculated on a net basis. In the
acquisition of the Energy Trading Business, Allegheny Energy Supply acquired no
outstanding payables or receivables and therefore they are not reflected in
these financial statements.
5. TRADING ACTIVITIES
The Energy Trading Business's energy trading activities exposes it to market and
credit risks. As of December 29, 2000, the Energy Trading Business was subject
to Merrill Lynch's risk management procedures. These risks are managed on a
portfolio basis, subject to parameters established by these risk management
procedures. Merrill Lynch ensures that the business units create and implement
processes to identify, measure, and monitor their risks within the established
parameters.
MARKET RISK
Market risk is the potential change in an instrument's value caused by
fluctuations in interest rates, commodity prices, or other market factors. The
Energy Trading Business is primarily exposed to commodity-driven risks
associated with the wholesale marketing of electricity and natural gas. The
commodity price risk exposure results from market fluctuations in the price and
transportation costs of electricity, natural gas, and other energy commodities.
The level of market risk is influenced by the volatility and the liquidity in
the markets in which financial instruments are traded.
The Energy Trading Business seeks to mitigate market risk associated with energy
commodity contracts by employing hedging strategies that correlate rate, price,
and spread movements of commodity contracts and related hedging activities.
However, the Energy Trading Business does not hedge the entire exposure from
commodity price volatility for a variety of reasons. To the extent the Energy
Trading Business does not hedge against commodity price volatility, the Energy
Trading Business's results of operations and financial position may be affected
either favorably or unfavorably by a shift in the future market prices.
CREDIT RISK
The Energy Trading Business is engaged in various trading activities in which
counterparties primarily include electric and gas utilities, oil and gas
exploration and production companies, and energy marketers. The Energy Trading
Business is exposed to a risk of loss if a counterparty fails to perform its
contractual obligations. The risk of loss depends on the creditworthiness of the
counterparty or issuer of the instrument. As of December 29, 2000, the Energy
Trading Business was subject to Merrill Lynch's procedures for mitigating credit
risk, including reviewing and establishing limits on credit exposure,
maintaining collateral, entering into master netting agreements and continually
assessing the creditworthiness of counterparties.
F-42
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
The Energy Trading Business has a concentration of customers in the electric and
gas utility and oil and gas exploration and production industries. Since
concentrations of credit risk can be affected by changes in political, industry,
or economic factors, these concentrations in customers may impact the Energy
Trading Business's overall exposure to credit risk, either positively or
negatively, in that the customers may be similarly affected by changes in
political, industry, or economic factors. Based on the Energy Trading
Business's policies, counterparty exposures, and its evaluation of credit as a
factor in determining the fair value of its financial instruments, the Energy
Trading Business does not anticipate a counterparty non-performance which would
have a material adverse effect on its financial position or results of
operations. As of December 29, 2000, the fair value of the Energy Trading
Business's commodity contracts with one customer of $366.2 million was
approximately 52% of the Energy Trading Business's total assets. The Energy
Trading Business recorded net trading revenues from this customer of $319.4
million for 2000.
TRADING POSITIONS
As of December 29, 2000, the gross contractual or notional amounts of derivative
financial instruments used for trading purposes, exclusive of the Spark Spread
Options, as discussed below, are as follows:
December 29, 2000
-----------------
Maximum
Purchased Sold Term in Years
--------- ---- -------------
Natural Gas (MMBTU's)
Options 1,082,910 1,584,696 1
Swaps 104,853,697 64,184,497 5
----------- ----------
Total Natural Gas 105,936,607 65,769,193
=========== ==========
Electricity (MWHs)
Options 36,842,848 39,861,401 10
Physicals 61,342,632 60,462,462 10
Swaps 35,200 32,000 2
----------- ----------
Total Electricity 98,220,680 100,355,863
========== ===========
The gross notional amount of interest rate swaps was $367.0 million and the
maximum term in years was 9.
CONTRACTUAL CONTROL OF CAPACITY
In 2000, the Energy Trading Business executed a significant option transaction
with one counterparty (the "Spark Spread Option"). Under the terms of the Spark
Spread Option, the Energy Trading Business pays a monthly premium of
approximately $3.5 million (approximately $42 million annually) that increases
to approximately $4.2 million (approximately $51 million annually) over the
18-year term of the transaction. The Energy Trading Business has the right to
receive 25% of the total available generating capacity of three generating
stations in Southern California. These three generating stations have
approximately 4,000 MW of total capacity (the Energy Trading Business's share
is approximately 1,000 MW). When the Energy Trading Business exercises its right
to call the available capacity, the Energy Trading Business pays a strike price
based on an index price for natural gas in southern California and a specific
heat rate based on the available MW of capacity plus other costs such as
start-up costs and a variable rate. The notional power quantity is 1,000 MWH per
hour, seven days per week, for the 18-year contract term. Guaranteed
availability of the capacity of the three generating stations per the contract
is 87.5% for each contract year. The Energy Trading Business must notify the
counterparty one-day in advance of its intent to exercise the option on any
given day. The Energy Trading Business has typically sold the electricity
purchased under the option transaction in the western United States.
The option transaction in California is unique given the long-term nature,
pricing structure, and location of the transaction. There are no observable
prices for transactions of a similar nature providing directly comparable
pricing data that could be
F-43
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
used in determining the fair value of this option. In addition, the energy under
the option is delivered to the Energy Trading Business at a relatively illiquid
pricing point in Southern California. Management utilizes a proprietary pricing
model to estimate the fair value of the option. Inputs to the pricing model
include premiums payable, estimated forward gas and power prices, interest
rates, estimates of market volatility for gas and power prices, power
availability, estimated start up costs, heat rates, and the estimated
correlation between gas and power prices. The estimated fair value represents
management's best estimate of an amount that could be realized, at the illiquid
pricing point, noted above. It could be materially different from an amount that
might be realized in an actual sale transaction. The Energy Trading Business has
entered into various physical and derivative transactions, as well as obtaining
insurance for protection against unit outages, to manage the price risk inherent
in the option transaction and continually adjusts such positions in response to
changing market conditions. However, because of the nature of the transaction
and the required pricing location, the degree to which price risk in the option
can be managed or mitigated by more liquid derivative instruments may vary
significantly over time. This portfolio, which consists of the spark spread
option and its related hedges, insurance, and interest rate swap, constitutes
approximately $35.1 million of net trading revenues during the year 2000 and
$81.9 million of the net assets acquired.
6. PROPERTY, PLANT, AND EQUIPMENT
The Energy Trading Business did not have any capitalized property, plant, and
equipment as of December 29, 2000. The cost of office space, computer equipment,
computer software, and other equipment used by the Energy Trading Business was
charged to the Energy Trading Business by Merrill Lynch as an operating expense
and is included in the direct expenses of the Energy Trading Business in the
Statement of Revenues and Direct Expenses. Also, Merrill Lynch expensed the cost
of its trading system software in the periods that the costs were incurred based
on Merrill Lynch's capitalization policy for software. No property, plant, and
equipment was acquired by Allegheny Energy Supply as a part of the purchase of
the Energy Trading Business.
Allegheny Energy Supply did acquire the trading system software used by the
Energy Trading Business as part of the purchase of the business. Allegheny
Energy Supply estimated the fair value of the trading system software as of
March 16, 2001 to be $2.5 million based on information provided by the software
vendor and other sources of information. No other items of property, plant, and
equipment were determined to have fair value as a result of the acquisition of
the Energy Trading Business on March 16, 2001.
7. EMPLOYEE BENEFITS
Allegheny Energy Supply did not assume an obligation for employee benefits from
Merrill Lynch under the terms of the purchase agreement, including obligations
for pension, medical, dental, and accrued vacation benefits. Allegheny Energy
Supply did agree to make certain payments to employees for retention bonuses and
for flexible spending accounts on the condition that Merrill Lynch first pay
such amounts to Allegheny Energy Supply, including related payroll taxes.
Accordingly, no liabilities related to employee benefits are included in the
Statement of Assets Acquired and Liabilities Assumed.
8. OTHER EMPLOYEE MATTERS
Under the terms of the purchase agreement, 21 employees of the Energy Trading
Business were identified as "key employees". All of the 21 "key employees"
accepted employment with Allegheny Energy Supply.
9. RELATED PARTIES
The Energy Trading Business's operations were highly integrated with the
operations of Merrill Lynch. Merrill Lynch's risk management, treasury, and
finance functions, which supported the Energy Trading Business's energy trading
operations, also supported other trading operations within Merrill Lynch. This
included the Energy Trading Business's cash margin account which was maintained
with Merrill Lynch. The risk management, treasury, and finance functions of
Merrill Lynch were not acquired by Allegheny Energy Supply as part of the
business.
F-44
Global Energy Markets
NOTES TO FINANCIAL STATEMENTS--
For the Year Ended December 29, 2000
The Energy Trading Business operated as a separate management center within
Merrill Lynch. As a management center, Merrill Lynch charged to the Energy
Trading Business the direct costs of its operations as expenses, including an
allocated share of the cost of certain plant, property, and equipment utilized
by Energy Trading Business. These allocated costs included office building
space, use of computer equipment, and use of software. During 2000, the
following amounts were charged to the Energy Trading Business by Merrill Lynch
which are classified as expenses in the Statement of Revenues and Direct
Expenses:
(Thousands of dollars) 2000
----
Compensation and benefits of employees $11,520
Occupancy 151
Communications and technology 2,644
Travel and entertainment 201
Professional fees 772
Other expenses 557
----------
Total $15,845
==========
At December 29, 2000, no liabilities were assumed for amounts due to Merrill
Lynch for the operating expenses of the Energy Trading Business. Compensation
and benefits of employees, communications and technology, travel and
entertainment and professional fees were directly related to the business based
upon the individuals within the business unit, the internal transfer price
designed to reflect the cost of the service for communication and technology
equipment utilized by the business unit, and direct expenses incurred by the
business. Occupancy costs have been allocated based on square footage. Other
expenses represent various costs charged to the Energy Trading Business by
Merrill Lynch for items directly consumed by the business, such as
transportation expenses and office supplies, and certain other allocated costs
Merrill Lynch charges to its management centers.
10. SUBSEQUENT EVENT
On December 7, 2001, Nevada Power Company or NPC filed a complaint against
Allegheny Energy Supply with FERC contending that the price of energy in three
forward sales agreements was excessive and should be substantially reduced by
FERC. Merrill Lynch negotiated and was a party to these agreements with NPC,
which were entered into between December 2000 and February 2001, and required
delivery of energy beginning on January 1, 2002 through December 31, 2002.
Allegheny Energy Supply later purchased these agreements as part of its
acquisition of the Energy Trading Business from Merrill Lynch in March 2001. In
general, NPC claims that the negotiated prices were unduly influenced by market
abnormalities in the southwest region of the United States. NPC asks FERC to
reform the price in these agreements to reflect current market conditions.
Allegheny Energy Supply believes NPC's complaint is without merit and intends to
vigorously defend the agreements with NPC before FERC.
As of December 29, 2000, the estimated fair value of the NPC contract reflected
in the statement of Assets Acquired and Liabilities Assumed was a liability of
$1.3 million.
F-45
OPERATING DATA FOR MIDWEST ASSETS ACQUIRED
FROM ENRON NORTH AMERICA CORPORATION
In May 2001, we acquired three natural gas-fired generating facilities totaling
1,710 MW of peaking capacity in Illinois, Indiana and Tennessee from Enron North
America Corporation. All three facilities had been in service with their former
owner since June 2000. They include the 508 MW Wheatland plant in Wheatland,
Indiana, the 656 MW Lincoln Energy Center plant in Manhattan, Illinois, and the
546 MW Gleason plant in Gleason, Tennessee. The table below provides historical
operating data for these generating assets from their in-service date until the
acquisition date:
Period from Three Months Ended
March 31, ------------------
2001 to May 3, March 31, December 31, September 30,
2001 2001 2000 2000 June 30, 2000
---- ---- ---- ---- -------------
Volumes (in
megawatt
hours) - - 5,406 138,140 22,736
Direct
Operating
Expenses (in
thousands) $3,133 $6,183 $7,733 $7,751 $2,794
The direct operating expenses primarily include the following types of expenses:
depreciation, outside services, utilities, insurance, materials and supplies,
fees and permits, rent expense, travel and entertainment, postage and freight,
right of way lease, advertising, communications, general business and
administrative, and other miscellaneous expenses.
O-1
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
OFFER TO EXCHANGE UP TO
$400,000,000
7.80% NOTES DUE 2011
WHICH HAVE BEEN REGISTERED UNDER THE
SECURITIES ACT OF 1933
FOR
ALL OUTSTANDING UNREGISTERED
7.80% NOTES DUE 2011
---------
PROSPECTUS
January , 2002
---------
PART II
INFORMATION NOT REQUIRED IN THE 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 company agreement. The Registrant's
Fourth Amended and Restated Limited Liability Company Agreement contains
provisions which eliminate liability to the fullest extent permitted by
applicable law.
The Registrant's Fourth Amended and Restated Limited Liability Company
Agreement provides that the Registrant's members and its officers, directors,
employees, agents and affiliates of the members of the Registrant (collectively,
the "Covered Persons") are entitled to be indemnified by the Registrant for, and
will not be held liable to the Registrant or any other person who has an
interest in or claim against the Registrant for any loss, damage or claim
incurred by reason of any act or omission performed or omitted by the Covered
Persons in good faith on behalf of the Registrant and in a manner reasonably
believed to be within the scope of the authority of the Agreement or applicable
law. Covered Persons will, however, be held liable to the Registrant or any
other person for any actions or omissions involving gross negligence or willful
misconduct by the Covered Person.
Indemnification has been expressly limited under the terms of the
Registrant's Fourth Amended and Restated Limited Liability Company Agreement to
the extent of the Registrant's assets and the members will not have any personal
liability therefor.
II-1
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(A) EXHIBITS
EXHIBITS DESCRIPTION
1.1 Purchase Agreement, dated March 9, 2001, between Allegheny Energy Supply Company, LLC and Salomon
Smith Barney Inc., as representative of the Initial Purchasers.*
2.1 Purchase and Sale Agreement, dated November 13, 2000, by and between Allegheny Energy Supply Company,
LLC and Enron North America Corp.*
2.2 Asset Contribution and Purchase Agreement, dated January 8, 2001, between Merrill Lynch & Co., Inc.
and Merrill Lynch Capital Services, Inc., as sellers and Allegheny Energy, Inc., Allegheny Energy
Supply Company, LLC and Allegheny Energy Global Markets, LLC, as purchasers.*
3.1 Certificate of Formation of Allegheny Energy Supply Company, LLC.*
3.2 Fourth Amended and Restated Limited Liability Company Agreement of Allegheny Energy Supply Company,
LLC.*
4.1 Registration Rights Agreement, dated March 15, 2001, between Allegheny Energy Supply Company, LLC and
Salomon Smith Barney Inc., as representative of the Initial Purchasers.*
4.2 Indenture dated as of March 15, 2001, between Allegheny Energy Supply Company, LLC and Bank One Trust
Company, N.A., as trustee.*
4.3 Form of New Note.*
5.1 Opinion of Sullivan & Cromwell.*
10.1 Power Sales Agreement, dated January 1, 2001, between Allegheny Energy Supply Company, LLC and West
Penn Power Company.*
10.2 Services Provision Agreement, dated May 22, 2000, between Allegheny Energy Supply Company, LLC and The
Potomac Edison Company.*
10.3 Services Provision Agreement relating to West Virginia rate
schedule, effective August 1, 2000, between Allegheny Energy
Supply Company, LLC and The Potomac Edison Company.*
10.4 Services Provision Agreement relating to Virginia rate schedule, effective August 1, 2000, between
Allegheny Energy Supply Company, LLC and The Potomac Edison Company.*
10.5 Power Sales Agreement, dated June 1, 2001, between Allegheny Energy Supply Company, LLC and
Monongahela Power Company.*
12.1 Computation in Support of Ratio of Earnings to Fixed Charges.
21.1 List of Subsidiaries of Allegheny Energy Supply Company, LLC.*
23.1 Consent of PricewaterhouseCoopers LLP.*
23.2 Consent of Sullivan & Cromwell (included in Exhibit 5.1).
23.3 Consent of PricewaterhouseCoopers LLP.
23.4 Consent of PricewaterhouseCoopers LLP.
25.1 Statement of Eligibility of Bank One Trust Company, N.A. on Form T-1.*
99.1 Form of Letter to Registered Holders.*
99.2 Form of Letter of Transmittal.*
99.3 Form of Notice of Guaranteed Delivery.*
99.4 Form of Instruction to Registered Holder from Beneficial Owner.*
II-2
EXHIBITS DESCRIPTION
-------- -----------
99.5 Form of Letter to Clients.*
99.6 Form of Letter to Depository Trust Company Participants.*
99.7 Form of Exchange Agent Agreement.*
(b) FINANCIAL STATEMENT SCHEDULES
Schedule 1.1 Valuation and Qualifying Accounts Schedule.*
Schedule 1.2 Report of PricewaterhouseCoopers LLP in connection with Audited
Financial Statement Schedule.*
- --------------------
* Previously filed.
II-3
ITEM 22. UNDERTAKINGS.
(a) The undersigned registrant hereby undertakes:
(1) That, for purposes of determining any liability under the Securities
Act of 1933, the information omitted from the form of prospectus filed
as part of this registration statement in reliance upon Rule 430A and
contained in a form of prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be
deemed to be part of this registration statement as of the time it was
declared effective;
(2) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement to include any
material information with respect to the plan of distribution not
previously disclosed in the registration statement or any material
change to such information in the registration statement;
(3) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be
deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time
shall be deemed to be the initial BONA FIDE offering thereof; and
(4) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unexchanged at the
termination of the offering.
(b) Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of
the registrant, pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities
(other than the payment by the registrant of expenses incurred or paid by a
director, officer or controlling person of the registrant in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the
matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Securities Act of 1933 and will
be governed by the final adjudication of such issue.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this Amendment No. 1 to the registration statement to
be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Hagerstown, State of Maryland, on December 6, 2001.
Allegheny Energy Supply Company, LLC
By: /s/ Alan J. Noia
------------------------------------
Name: Alan J. Noia
Title: Chairman, Chief Executive
Officer and Director
Pursuant to the requirements of the Securities Act of 1933, this
Amendment No. 1 to the registration statement has been signed by the following
persons in the capacities indicated on December 6, 2001.
SIGNATURE TITLE
--------- -----
/s/ Alan J. Noia Chairman, Chief Executive Officer and Director
- ------------------------------------ (Principal Executive Officer)
(Alan J. Noia)
/s/ Michael Morrell President, Chief Operating Officer and Director
- -----------------------------------
(Michael Morrell)
/s/ Bruce E. Walenczyk Vice President and Director
- ------------------------------------ (Principal Financial Officer)
(Bruce E. Walenczyk)
/s/ Thomas J. Kloc Controller
- ----------------------------------- (Principal Accounting Officer)
(Thomas J. Kloc)
/s/ Richard Gagliardi Director
- -----------------------------------
(Richard Gagliardi)
/s/ Thomas K. Henderson Vice President and Director
- -----------------------------------
(Thomas K. Henderson)
/s/ Jay S. Pifer Director
- -----------------------------------
(Jay S. Pifer)
/s/ Victoria V. Schaff Director
- -----------------------------------
(Victoria V. Schaff)
II-5
INDEX TO EXHIBITS
(a) EXHIBITS
EXHIBITS DESCRIPTION
1.1 Purchase Agreement, dated March 9, 2001, between Allegheny Energy Supply Company, LLC and Salomon
Smith Barney Inc., as representative of the Initial Purchasers.*
2.1 Purchase and Sale Agreement, dated November 13, 2000, by and between Allegheny Energy Supply Company,
LLC and Enron North America Corp.*
2.2 Asset Contribution and Purchase Agreement, dated January 8, 2001, between Merrill Lynch & Co., Inc.
and Merrill Lynch Capital Services, Inc., as sellers and Allegheny Energy, Inc., Allegheny Energy
Supply Company, LLC and Allegheny Energy Global Markets, LLC, as purchasers.*
3.1 Certificate of Formation of Allegheny Energy Supply Company, LLC.*
3.2 Fourth Amended and Restated Limited Liability Company Agreement of Allegheny Energy Supply Company,
LLC.*
4.1 Registration Rights Agreement, dated March 15, 2001, between Allegheny Energy Supply Company, LLC and
Salomon Smith Barney Inc., as representative of the Initial Purchasers.*
4.2 Indenture dated as of March 15, 2001, between Allegheny Energy Supply Company, LLC and Bank One Trust
Company, N.A., as trustee.*
4.3 Form of New Note.*
5.1 Opinion of Sullivan & Cromwell.*
10.1 Power Sales Agreement, dated January 1, 2001, between Allegheny Energy Supply Company, LLC and West
Penn Power Company.*
10.2 Services Provision Agreement, dated May 22, 2000, between Allegheny Energy Supply Company, LLC and The
Potomac Edison Company.*
10.3 Services Provision Agreement relating to West Virginia rate
schedule, effective August 1, 2000, between Allegheny Energy
Supply Company, LLC and The Potomac Edison Company.*
10.4 Services Provision Agreement relating to Virginia rate schedule, effective August 1, 2000, between
Allegheny Energy Supply Company, LLC and The Potomac Edison Company.*
10.5 Power Sales Agreement, dated June 1, 2001, between Allegheny Energy Supply Company, LLC and
Monongahela Power Company.*
12.1 Computation in Support of Ratio of Earnings to Fixed Charges.
21.1 List of Subsidiaries of Allegheny Energy Supply Company, LLC.*
23.1 Consent of PricewaterhouseCoopers LLP.*
23.2 Consent of Sullivan & Cromwell (included in Exhibit 5.1).
23.3 Consent of PricewaterhouseCoopers LLP.
23.4 Consent of PricewaterhouseCoopers LLP.
25.1 Statement of Eligibility of Bank One Trust Company, N.A. on Form T-1.*
99.1 Form of Letter to Registered Holders.*
99.2 Form of Letter of Transmittal.*
99.3 Form of Notice of Guaranteed Delivery.*
99.4 Form of Instruction to Registered Holder from Beneficial Owner.*
II-6
EXHIBITS DESCRIPTION
-------- -----------
99.5 Form of Letter to Clients.*
99.6 Form of Letter to Depository Trust Company Participants.*
99.7 Form of Exchange Agent Agreement.*
(b) FINANCIAL STATEMENT SCHEDULES
Schedule 1.1 Valuation and Qualifying Accounts Schedule.*
Schedule 1.2 Report of PricewaterhouseCoopers LLP in connection with Audited
Financial Statement Schedule.*
- --------------------
* Previously filed.
II-7