As filed with the Securities and Exchange Commission on August 21, 2001
Registration No. 333-66032
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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AMENDMENT NO. 1
TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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PG&E NATIONAL ENERGY GROUP, INC.
(Exact name of Registrant as specified in its charter)
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Delaware 4911 94-3316236
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification No.)
7600 Wisconsin Avenue
(mailing address: 7500 Old Georgetown Road)
Bethesda, Maryland 20814
(301) 280-6800
(Address, including zip code, and telephone number,
including area code, of Registrant's principal executive offices)
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STEPHEN A. HERMAN, ESQ.
Senior Vice President and General Counsel
7500 Old Georgetown Road
Bethesda, Maryland 20814
(301) 280-6815
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
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Copy to:
LESLIE P. JAY, ESQ.
Orrick, Herrington & Sutcliffe LLP
400 Sansome Street
San Francisco, California 94111
(415) 392-1122
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Approximate date of commencement of proposed sale 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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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.
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++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this prospectus is not complete and may be changed. We may +
+not sell these securities until the registration statement filed with the +
+Securities and Exchange Commission is effective. This prospectus is not an +
+offer to sell these securities and is not soliciting an offer to buy these +
+securities in any jurisdiction where the offer or sale is not permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Preliminary Prospectus Subject to Completion, Dated August 21, 2001
[LOGO OF PG&E APPEARS HERE]
PG&E NATIONAL ENERGY GROUP, INC.
Offer to Exchange $1,000,000,000 10.375% Senior Notes due May 16, 2011 for
$1,000,000,000 10.375% Senior Notes due May 16, 2011
which have been registered under the Securities Act of 1933
The exchange offer will expire at 5:00 p.m.,
New York City time, on , 2001, unless extended.
-----------
Material Terms of the Exchange Offer:
. We are offering to exchange notes registered under the Securities Act of
1933, as amended, for a like principal amount of original notes that we
issued in a private placement that closed on May 22, 2001.
. The terms of the exchange notes are substantially identical to the terms of
the original notes, except that the exchange notes will not contain transfer
restrictions and will not have the registration rights that apply to the
original notes or entitle their holders to additional interest for our
failure to comply with these registration rights. The terms and conditions of
the exchange offer are more fully described in this prospectus.
. You may withdraw tenders of original notes at any time prior to the
expiration of the exchange offer. We will exchange all original notes that
are validly tendered and not withdrawn prior to the expiration of the
exchange offer.
. We will not receive any proceeds from the exchange offer.
. There is no existing market for the exchange notes offered by this prospectus
and we do not intend to apply for their listing on any securities exchange or
any automated quotation system.
. We believe that the exchange of original notes for exchange notes will not be
a taxable event for United States federal income tax purposes.
You should consider carefully the "Risk Factors" beginning on page 13 of this
prospectus before tendering your original notes for exchange.
-----------
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
adequacy or the accuracy of this prospectus. Any representation to the contrary
is a criminal offense.
-----------
Prospectus dated , 2001.
TABLE OF CONTENTS
Summary................................................................... 1
Risk Factors.............................................................. 13
Use of Proceeds........................................................... 26
The Exchange Offer........................................................ 27
Capitalization............................................................ 35
Selected Consolidated Financial Data...................................... 36
Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 40
Business.................................................................. 56
Management................................................................ 91
Relationship with PG&E Corporation and Related Transactions................. 100
Description of the Notes.................................................... 105
Certain United States Federal Income Tax Consequences....................... 117
Plan of Distribution........................................................ 119
Legal Matters............................................................... 120
Experts..................................................................... 120
Available Information....................................................... 121
Index to Consolidated Financial Statements.................................. F-1
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER RSA 421-B WITH THE STATE OF NEW HAMPSHIRE NOR THE
FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE
STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY
DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NONE OF
THESE FACTS, NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A
SECURITY OR A TRANSACTION, MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY
WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO,
ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE
MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION
INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.
i
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus includes forward-looking statements. We have based these
forward-looking statements on our current expectations and projections about
future events based upon our knowledge of facts as of the date of this
prospectus and our assumptions about future events. These forward-looking
statements are subject to various risks and uncertainties that may be outside
our control including, among other things:
. the direct and indirect effects of the current California energy crisis
on us, including the measures adopted and being contemplated by federal
and state authorities to address the crisis;
. the effect of the Pacific Gas and Electric Company bankruptcy proceedings
upon our parent, PG&E Corporation, and upon us;
. fluctuations in commodity fuel and electricity prices and any resulting
increases in the cost of producing power and/or decreases in prices of
power we sell, and our ability to manage such fluctuations and changing
prices;
. illiquidity in the commodity energy market and our ability to provide the
credit enhancements necessary to support our trading activities;
. legislative and regulatory initiatives regarding deregulation and
restructuring of the electric and natural gas industries in the United
States;
. the pace and extent of the restructuring of the electric and natural gas
industries in the United States;
. the extent and timing of the entry of additional competition into the
power generation, energy marketing and trading and natural gas
transmission markets;
. our pursuit of potential business strategies, including acquisitions or
dispositions of assets or internal restructuring;
. the extent to which our current or planned development of generating
facilities, pipelines and storage facilities are completed and the pace
and cost of that completion, including the extent to which commercial
operations of these development projects are delayed or prevented because
of various development and construction risks such as the failure to
obtain necessary permits or equipment, the failure of third party
contractors to perform their contractual obligations, or the failure of
necessary equipment to perform as anticipated;
. our ability to obtain financing for all planned development and to
refinance our and our subsidiaries' existing indebtedness, in each case,
on reasonable terms;
. restrictions imposed upon us under certain term loans of PG&E
Corporation;
. the extent and timing of generating, pipeline and storage capacity
expansion and retirements by others;
. changes in or application of federal, state and other regulations to
which we, our subsidiaries and/or the projects in which we invest are
subject;
. changes in or application of environmental and other laws and regulations
to which we and our subsidiaries and the projects in which we invest are
subject;
. political, legal and economic conditions and developments in North
America where we and our subsidiaries and the projects in which we invest
operate;
. financial market conditions and changes in interest rates;
. weather and other natural phenomena; and
. our performance of projects undertaken and the success of our efforts to
invest in and develop new opportunities.
ii
Although we believe that the expectations reflected in the forward-looking
statements are reasonable, we cannot guarantee future results, events, levels
of activity, performance or achievements.
We use words like "anticipate," "estimate," "intend," "project," "plan,"
"expect," "will," "believe," "could" and similar expressions to help identify
forward-looking statements in this prospectus.
For additional factors that could affect the validity of our forward-looking
statements, you should read "Risk Factors." In light of these and other risks,
uncertainties and assumptions, actual events or results may be very different
from those expressed or implied in the forward-looking statements in this
prospectus, or may not occur. We do not undertake any obligation to update or
revise any forward-looking statement, whether as a result of new information,
future events or otherwise.
iii
SUMMARY
This summary highlights some information from this prospectus, including
information about the exchange offer, but it may not contain all of the
information that may be important to you in deciding whether to exchange your
original notes for exchange notes. You should read this entire prospectus
carefully. The term "original notes" as used in this prospectus refers to our
outstanding 10.375% senior notes due 2011 that we issued on May 22, 2001 and
that have not been registered under the Securities Act. The term "exchange
notes" refers to the 10.375% senior notes due 2011 offered under this
prospectus. The term "notes" refers to the original notes and the exchange
notes collectively.
Our Company
We are an integrated energy company with a strategic focus on power
generation, greenfield development, natural gas transmission and wholesale
energy marketing and trading in North America. We have integrated our
generation, development and energy marketing and trading activities to increase
the returns from our operations, identify and capitalize on opportunities to
increase our generating and pipeline capacity, create energy products in
response to dynamic markets and manage risks. We intend to expand our
generating and natural gas pipeline capacity and enhance our growth and
financial returns through our energy marketing and trading capabilities.
We own, manage and control the electric output of generating facilities in
targeted North American markets. As of June 30, 2001, we had ownership or
leasehold interests in 23 operating generating facilities with a net generating
capacity of 6,438 megawatts, or MW, as follows:
Number of Net Primary % of
Facilities MW Fuel Type Portfolio
---------- ----- ----------- ---------
10 2,997 Coal/Oil 47
9 2,263 Natural Gas 35
3 1,166 Water 18
1 12 Wind --
----------- ----- ---------
23 6,438 100
In addition, we have seven facilities totaling 5,480 MW in construction and
we control, through various arrangements, an additional 518 MW in operation and
2,188 MW in construction, giving us a total owned and controlled generating
capacity in operation or construction of 14,624 MW. We also own or control
7,559 MW of primarily baseload, natural gas-fired projects in advanced
development. Through these projects, we intend to further grow and regionally
diversify our generating portfolio to at least 22,183 MW by the end of 2004.
We also own, operate and develop natural gas pipeline facilities, including
our Gas Transmission Northwest, or GTN, pipeline and a North Baja pipeline
under development. GTN consists of over 1,300 miles of natural gas transmission
mainline pipe with a capacity of 2.7 billion cubic feet of natural gas per day.
This pipeline is the only interstate pipeline directly linking the natural gas
reserves in Western Canada to the gas markets of California and parts of the
Pacific Northwest, and we expect to expand its capacity by at least 500 million
cubic feet per day by the end of 2004. We are in advanced stages of development
of a North Baja pipeline which will run from Arizona to Northern Mexico and
will have an expected initial capacity of 500 million cubic feet per day by
late 2002.
We engage in the marketing and trading of electricity and various fuels and
other energy-related commodities throughout North America. We aggregate
electricity and related products from our owned and controlled generating
facilities and our energy marketing and trading positions and manage the fuel
supply and sale of electrical output. We also engage in trading to manage our
exposure to market risk.
1
During 2000, 33% of our income from continuing operations before provision
for income taxes, interest expense, depreciation, amortization and certain
other adjustments, or Adjusted EBITDA, came from GTN, 26% came from USGen New
England, Inc., 18% came from our independent power projects and 23% came from
all other activities, net of general and administrative expenses, including
energy marketing and trading.
Our principal executive offices are located at 7600 Wisconsin Avenue
(mailing address: 7500 Old Georgetown Road), Bethesda, Maryland 20814. Our
telephone number is (301) 280-6800.
Our Business Strategy
We believe deregulation and the growing demand for electric power and
natural gas in the United States create attractive opportunities for integrated
energy companies like ours. Our objective is to become a leading integrated
energy company with a strong national presence by taking advantage of these
market opportunities. Our strategy to achieve this objective includes the
following components:
Expand Our Generating and Pipeline Capacity. We intend to expand our
generating and pipeline capacity through:
. Greenfield Development. We currently own 6,234 MW of power generating
projects in advanced development in the United States. We have secured
the turbines and sites necessary to complete these development projects
over the next four years.
. Contractual Control. We use our trading, marketing, financing and
development expertise to successfully identify, negotiate and structure
contracts to control the electric output of generating facilities owned
by third parties in targeted North American markets.
. Gas Transmission Growth. We plan to expand the capacity of our GTN
pipeline by at least 500 million cubic feet per day by the end of 2004.
We also plan to complete our North Baja pipeline, which will have an
expected initial capacity of 500 million cubic feet per day, by late
2002.
. Strategic Transactions. We intend to identify and pursue strategic
acquisitions that expand and complement our core operations. We also
expect to periodically divest assets to adjust our regional portfolios
and increase the availability of capital for further growth.
Expand Our Presence in Targeted Regions. We intend to expand our presence in
targeted regions to increase our operational flexibility, create economies of
scale, diversify our geographic presence, enhance our local market insight and
improve our ability to create diverse energy products. We have established a
strong regional presence in the Northeast and we are strengthening our presence
in the Midwestern, Southern and Western regions of the United States through
expanded energy marketing and trading activities and development and
contractual control of generating capacity in these regions.
Expand Our Integrated Energy Marketing and Trading Operations. We intend to
grow our integrated energy marketing and trading operations to enhance and
optimize the financial performance of our owned and controlled generating
facilities, pipelines and storage facilities, and to manage associated risks.
We also intend to expand and diversify our product offerings to satisfy the
rapidly evolving needs of our integrated operations and our expanding customer
base.
Pursue Operational Excellence. We continually seek to maximize the revenue
potential of our integrated operations and minimize our operating and
maintenance expenses and fuel costs. We believe that our continued success in
achieving these operational goals will improve the earnings of our generating
facilities by increasing the percentage of hours that they are available to
generate power, particularly during peak energy price periods. We also intend
to capitalize on e-commerce applications in order to lower our costs.
2
Manage Our Growth to Maintain Credit Quality. Through our development
activities and our turbine options, we have the ability to rapidly expand our
generating capacity. In order to maintain our current credit quality while
constructing and placing in operation all of our 6,234 MW of owned power
generating projects in advanced development on our desired schedule, we would
require additional equity capital from third parties, which equity could
include an initial public offering of our common stock. We intend to raise
equity as required to maintain our credit quality while executing our growth
strategy, timing our growth to coincide with the availability of capital.
Our Structure
We are a holding company that conducts all of its operations through its
subsidiaries. We are an indirect wholly owned subsidiary of PG&E Corporation,
which is also the parent of Pacific Gas and Electric Company, the California
regulated utility. On April 6, 2001, Pacific Gas and Electric Company filed a
voluntary petition for relief under the provisions of Chapter 11 of the U.S.
Bankruptcy Code. Although PG&E Corporation is our common parent, we are not the
same company as Pacific Gas and Electric Company. Pursuant to the California
Public Utilities Commission's order allowing PG&E Corporation to be established
as a holding company, our operations, financing activities and books and
records are maintained independent of Pacific Gas and Electric Company.
In addition, we recently undertook a corporate restructuring, known as a
"ringfencing" transaction. A "ringfencing" transaction is the creation or use
of an entity following credit rating agency criteria designed to further
separate a subsidiary from its parent and affiliates, thereby enabling that
"ringfenced" subsidiary to obtain or retain credit ratings for itself separate
from its parent and its affiliates that are not inside the "ringfence." Our
"ringfencing" transaction involved the creation or use of entities as
intermediate owners between PG&E Corporation and us, between us and certain of
our subsidiaries and between our subsidiaries and other subsidiaries. These
"ringfencing" entities are: PG&E National Energy Group, LLC, or the LLC, which
owns 100% of our capital stock; GTN Holdings, LLC, which owns 100% of the
capital stock of PG&E Gas Transmission, Northwest Corporation, which owns our
primary natural gas pipeline business; and PG&E Energy Trading Holdings, LLC,
which owns our energy trading subsidiaries.
Our organizational documents and those of these "ringfencing" entities were
modified to provide for the creation of an "independent member" of the board of
directors or board of control of each such entity. In furtherance of the rating
agency criteria, each entity's board of directors or board of control,
including the independent director, must unanimously approve certain corporate
matters, including:
. a consolidation or merger with any entity;
. the transfer of 75% or more of our or the affected entity's assets;
. the institution or consent to institution of a bankruptcy, insolvency, or
similar proceeding or action; or
. the declaration or payment of dividends or similar distributions.
In addition, our organizational documents and those of these "ringfencing"
entities require that the "independent member" of the board of directors or
board of control of each such entity confirm compliance with either a financial
ratio or credit rating threshold prior to the making of a dividend, a similar
distribution or an intercompany loan to any owner or affiliate.
The restrictions on the activities of the "ringfencing" entities are
consistent with rating agency criteria designed to further separate the assets
and affairs of a parent and subsidiary, thereby permitting an assignment of a
credit rating to a subsidiary based on the subsidiary's own risks, merits and
general creditworthiness. Following the completion of our "ringfencing"
transaction, on January 18, 2001, Standard & Poor's Ratings Services assigned
us a corporate rating of "BBB" and on February 20, 2001, Moody's Investors
Services
3
assigned us a corporate credit rating of "Baa2." On April 6, 2001, following
the bankruptcy filing by Pacific Gas and Electric Company, Standard & Poor's
affirmed our "BBB" corporate credit rating, and our "Baa2" corporate credit
rating was affirmed by Moody's on April 9, 2001.
The following chart depicts a summarized version of our legal structure and
our relationship to Pacific Gas and Electric Company, and shows Moody's and
Standard & Poor's ratings for rated entities. This chart excludes some
intermediate and other entities in our legal structure. All "ringfencing"
entities are indicated by broken lines.
-------------------------
PG&E Corporation
-------------------------
- ---------------------- -------------------------
Pacific Gas and PG&E National Energy
Electric Company Group, LLC.
- ---------------------- (The LLC)
-------------------------
-------------------------
PG&E National Energy
Group, LLC.
(The Issuer)
(Baa2/BBB)
-------------------------
------------------------------
PG&E National Energy
Group Holdings Corporation
------------------------------
------------------------- ------------------------- -------------------------
GTE Holdings, LLC PG&E Energy Trading PG&E Generating
------------------------- Holdings, LLC Company, LLC
------------------------- (Baa2/BBB)
-------------------------
------------------------- ------------------
PG&E Energy Trading IPP Projects
Holdings Corporation ------------------
------------------------- (unrated/BBB+) ------------------
------------------------- Merchant
PG&E Gas Transmission, Projects
Northwest Corporation ------------------------- ------------------
(GTN) Various Energy Trading ------------------
(Baa1/A-) Subsidiaries USGen
------------------------- New England, Inc.
------------------------- (Baa2/BBB)
------------------
4
SUMMARY OF THE EXCHANGE OFFER
On May 22, 2001, we completed the private offering of $1 billion in
aggregate principal amount of our 10.375% senior notes due 2011. These original
notes were not registered under the Securities Act and, therefore, they are
subject to significant restrictions on resale. Accordingly, when we sold these
original notes, we entered into a registration rights agreement with the
initial purchasers that requires us to deliver to you this prospectus and to
permit you to exchange your original notes for exchange notes that have
substantially identical terms to the original notes, except that the exchange
notes will be freely transferable and will not have covenants regarding
registration rights or additional interest. The exchange notes will be issued
under the same indenture under which the original notes were issued and, as a
holder of the exchange notes, you will be entitled to the same rights under the
indenture that you had as a holder of original notes. The original notes and
the exchange notes will be treated as a single series of notes under the
indenture.
Set forth below is a summary description of the terms of the exchange offer.
Exchange Offer...................... We are offering to exchange up to $1
billion in aggregate principal amount of
exchange notes for a like aggregate
principal amount of original notes.
Original notes may be tendered only in
denominations of $100,000 or integral
multiples of $1,000 in excess thereof.
Expiration Date..................... The exchange offer will expire at 5:00
p.m., New York City time, on ,
2001, unless we extend it. We do not
currently intend to extend the exchange
offer.
Interest on the Exchange Notes...... Interest on the exchange notes will
accrue at the rate of 10.375% from the
date of the last periodic payment of
interest on the original notes or, if no
interest has been paid, from May 22,
2001, the original issue date of the
original notes.
Conditions to the Exchange Offer.... The exchange offer is subject to
customary conditions, including that:
. there is no change in law,
regulation or any applicable
interpretation of the SEC staff that
prevents us from proceeding with the
exchange offer; and
. there is no action or proceeding,
pending or threatened, that would
impair our ability to proceed with
the exchange offer.
Procedure for Exchanging Original If the original notes you wish to
Notes.............................. exchange are registered in your name:
. you must complete, sign and date the
letter of transmittal and mail or
otherwise deliver it, together with
any other required documentation, to
Wilmington Trust Company, as
exchange agent, at the address
specified on the cover page of the
letter of transmittal.
If the original notes you wish to
exchange are in book-entry form and
registered in the name of a broker,
dealer or other nominee:
. you must contact the broker, dealer,
commercial bank, trust company or
other nominee in whose name your
5
original notes are registered and
instruct it to tender your original
notes on your behalf. You must
comply with The Depository Trust
Company's procedures for tender and
delivery of book-entry securities in
order to validly tender your
original notes for exchange.
Questions regarding the exchange of
original notes or the exchange offer
generally should be directed to the
exchange agent at the address specified
in "The Exchange Offer--Exchange Agent."
Guaranteed Delivery Procedures...... If you wish to exchange your original
notes and you cannot get the required
documents to the exchange agent by the
expiration date or you cannot tender and
deliver your original notes in accordance
with DTC's procedures by the expiration
date, you may tender your original notes
according to the guaranteed delivery
procedures described under the heading
"The Exchange Offer--Guaranteed Delivery
Procedures."
Withdrawal Rights................... You may withdraw the tender of your
original notes at any time before 5:00
p.m., New York City time, on the
expiration date of the exchange offer.
Acceptance of Original Notes and
Delivery of Exchange Notes......... We will accept for exchange any and all
original notes that are properly tendered
in the exchange offer before 5:00 p.m.,
New York City time, on the expiration
date, as long as all of the terms and
conditions of the exchange offer are met.
We will deliver the exchange notes
promptly following the expiration date.
Resale of Exchange Notes............ Based on interpretations by the staff of
the SEC, as detailed in a series of no-
action letters issued by the SEC to third
parties, we believe that you may offer
for resale, resell or otherwise transfer
the exchange notes without complying with
the registration and prospectus delivery
requirements of the Securities Act if:
. you are acquiring the exchange notes
in the ordinary course of your
business and do not hold any
original notes to be exchanged in
the exchange offer that were
acquired other than in the ordinary
course of business;
. you are not a broker-dealer
tendering original notes acquired
directly from us;
. you are not participating, do not
intend to participate and have no
arrangements or understandings with
any person to participate in the
exchange offer for the purpose of
distributing the exchange notes; and
. you are not our "affiliate," within
the meaning of Rule 405 under the
Securities Act.
Each broker or dealer that receives
exchange notes for its own account in
exchange for original notes that were
acquired as a result of market-making or
other trading activities must acknowledge
that it will deliver a prospectus meeting
the
6
requirements of the Securities Act in
connection with any resale of the
exchange notes.
Consequences of Failure to If you do not exchange your original
Exchange........................... notes for exchange notes, you will not be
able to offer, sell or otherwise transfer
the original notes except:
. in compliance with the registration
requirements of the Securities Act
and any other applicable securities
laws,
. pursuant to an exemption from the
securities laws, or
. in a transaction not subject to the
securities laws.
Original notes that remain outstanding
after completion of the exchange offer
will continue to bear a legend reflecting
these restrictions on transfer. In
addition, upon completion of the exchange
offer, you will not be entitled to any
rights to have the resale of original
notes registered under the Securities Act
(subject to limited exceptions applicable
only to certain qualified institutional
buyers.) We currently do not intend to
register under the Securities Act the
resale of any original notes that remain
outstanding after completion of the
exchange offer.
Certain Tax Considerations.......... We believe that the exchange of original
notes for exchange notes will not be a
taxable event for U.S. federal income tax
purposes. For additional information,
read the discussion under "Certain United
States Federal Income Tax Consequences"
beginning on page 117.
Exchange Agent...................... Wilmington Trust Company is serving as
exchange agent for the exchange offer.
7
SUMMARY DESCRIPTION OF THE EXCHANGE NOTES
The terms of the exchange notes we are issuing in the exchange offer and the
original notes are identical in all material respects, except that:
. the exchange notes will have been registered under the Securities Act;
. the exchange notes will not contain transfer restrictions; and
. the exchange notes will not have the registration rights that apply to
the original notes or entitle their holders to additional interest for
our failure to comply with these registration rights.
A brief description of the material terms of the exchange notes is set forth
below:
Securities offered.................. $1,000,000,000 principal amount of
10.375% senior notes due 2011.
Maturity............................ May 16, 2011.
Interest payment dates.............. May 15 and November 15 of each year,
beginning on November 15, 2001.
Ranking............................. The exchange notes will be our senior
obligations, will rank equally with all
of our existing obligations (including
any original notes that are not exchanged
in the exchange offer) and future senior
obligations and will rank senior to all
of our future subordinated indebtedness.
We are a holding company with all of our
operations conducted through our
subsidiaries. All indebtedness and other
liabilities of our subsidiaries will be
effectively senior to the exchange notes.
Ratings............................. The exchange notes have been assigned a
rating of "Baa2" by Moody's and "BBB" by
Standard & Poor's, the same ratings
assigned to the original notes.
Optional redemption................. We may redeem any or all of the exchange
notes at a redemption price equal to the
greater of:
. 100% of the principal amount of the
exchange notes being redeemed; or
. the sum of the present values of the
remaining scheduled payments of
principal and interest on the
exchange notes being redeemed
discounted to the date of redemption
on a semiannual basis at a rate
equal to the equivalent yield to
maturity at that time of a fixed
rate United States treasury security
with a maturity comparable to the
remaining term to maturity of the
exchange notes plus 50 basis points;
plus, in either case, accrued and unpaid
interest, if any, to the redemption date
on the principal amount of exchange notes
being redeemed.
Use of proceeds..................... We will not receive any proceeds from the
issuance of the exchange notes. We are
making the exchange offer solely to
satisfy our obligations under the
registration rights agreement.
8
SUMMARY HISTORICAL FINANCIAL DATA
The following tables present our summary historical financial data. The data
presented in these tables are from "Selected Consolidated Financial Data," and
our historical consolidated financial statements and notes to those statements
that are included elsewhere in this prospectus. You should read those sections
and the section entitled "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a further explanation of the financial
data summarized here. The historical financial information may not be
indicative of our future performance.
PG&E National Energy Group, Inc. was incorporated on December 18, 1998.
Shortly thereafter, PG&E Corporation contributed various subsidiaries to us.
Our consolidated financial statements for all periods presented in the tables
below have been prepared on a basis that includes the historical financial
position and results of operations of the subsidiaries that were wholly owned
or majority-owned and controlled by us as of December 31, 2000. For those
subsidiaries that were acquired or disposed of during the periods presented by
us, or by PG&E Corporation prior to or after our formation, the results of
operations are included from the date of acquisition. For those subsidiaries
disposed of during the periods presented, the results of operations are
included through the date disposed.
In addition, you should read our historical financial data in light of the
following:
. In September 1997, we became the sole owner of PG&E Generating Company, a
joint venture which owned, developed and managed independent power
projects. This joint venture was formerly known as U.S. Generating
Company or US Gen. In connection with this transaction, we acquired
various ownership interests that gave us full or part ownership of twelve
domestic generating facilities. In April 1997, we sold our interest in
International Generating Company, Ltd., an international developer of
generating facilities, resulting in an after-tax gain of $120 million.
Our 1997 results also reflect the write-off of our $87 million investment
in two generating facilities that we had developed and constructed in
Florida to burn agricultural waste, but only operated for a short period
of time because of a dispute with the power purchaser.
. In January 1997, we acquired Teco Pipeline Company for $378 million and,
in July 1997, Valero Energy Corporation's natural gas business located in
Texas for total consideration, including assumption of its debt, of
approximately $1.5 billion. These two operations, which we called GTT,
made up the bulk of our natural gas operations in Texas. On January 27,
2000, we signed a definitive agreement with El Paso Field Services
Company to sell GTT. We completed this sale on December 22, 2000. In
1999, we recognized a $1,275 million charge against pre-tax earnings
($890 million after tax) to reflect GTT's assets at their net realizable
value. In 2000, prior to the closing of the sale, we recognized income of
approximately $33 million.
. In September 1998, we acquired for approximately $1.8 billion a portfolio
of hydroelectric, coal, oil and natural gas generating facilities with an
aggregate generating capacity of 4,000 MW located in New England from New
England Power Company, or NEP, a subsidiary of New England Electric
System. We also assumed the purchase obligations under 23 multi-year
power purchase agreements representing an additional 800 MW of production
capacity. In return for our assumption of these power purchase
agreements, we are receiving the benefit of monthly payments from NEP
through January 2008. As of December 31, 2000, NEP owed gross payments of
$790 million under this arrangement. In connection with the acquisition,
we further agreed to provide electricity to certain retail providers in
New England at predetermined rates.
. In July 1998, we sold our Australian energy holdings for $126 million. We
recognized a $23 million loss related to the sale.
9
. One of the businesses that PG&E Corporation contributed to us in 1998
provided retail power and gas commodity products and energy management
services to end-users. Due to a revised assessment of the market
potential for retail energy services, we decided in December 1999 to sell
this business and reflected it in the financial statements as a
discontinued operation. Our 1999 results include losses aggregating $105
million after-tax, including the write-down of this business to its
estimated net realizable value and establishment of a reserve for
anticipated losses. We completed the sale of substantially all of this
business in two transactions in 2000, recording an additional after-tax
loss of $40 million in 2000.
. Some of the costs reflected in the consolidated financial data are for
functions and services provided by PG&E Corporation that are directly
attributable to us, which are charged to us based on usage and other
allocation factors, as well as general corporate expenses allocated by
PG&E Corporation based on assumptions that management believes are
reasonable under the circumstances.
Six Months Ended
Year Ended December 31, June 30,
------------------------------------------------- -----------------------
1996 1997 1998 1999 2000 2000 2001
----------- ----------- ------- ------- ------- ----------- -----------
(unaudited) (unaudited) (unaudited) (unaudited)
Income Statement Data
(in millions):
Operating revenues...... $426 $6,101 $10,650 $12,020 $16,995 $6,693 $6,964
Impairments and write-
offs................... 60 87 -- 1,275 -- -- --
Other operating
expenses............... 306 6,081 10,488 11,851 16,604 6,501 6,754
---- ------ ------- ------- ------- ------ ------
Total operating
expenses............ 366 6,168 10,488 13,126 16,604 6,501 6,754
---- ------ ------- ------- ------- ------ ------
Operating income
(loss)................. 60 (67) 162 (1,106) 391 192 210
Other income (expense):
Interest income....... 18 29 45 75 80 34 49
Interest expense...... (46) (81) (156) (162) (155) (78) (58)
Other, net............ 6 119 (7) 52 6 (9) 6
---- ------ ------- ------- ------- ------ ------
Income (loss) from
continuing operations
before income taxes.... 38 -- 44 (1,141) 322 139 207
Income tax expense
(benefit)............ 30 (32) 41 (351) 130 55 82
---- ------ ------- ------- ------- ------ ------
Income (loss) from
continuing operations.. 8 32 3 (790) 192 84 125
Discontinued
operations, net of
income taxes......... -- (28) (57) (105) (40) -- --
---- ------ ------- ------- ------- ------ ------
Net income (loss) before
cumulative effect of a
change in accounting
principle.............. 8 4 (54) (895) 152 84 125
Cumulative effect of a
change in accounting
principle, net of
income taxes........... -- -- -- 12 -- -- --
---- ------ ------- ------- ------- ------ ------
Net income (loss).... $ 8 $ 4 $ (54) $ (883) $ 152 $ 84 $ 125
==== ====== ======= ======= ======= ====== ======
Other Data:
Ratio of earnings to
fixed charges(1)....... 1.3 1.1 1.0 Note 2 2.2 2.1 2.7
- --------
(1) For purposes of calculating the ratio of earnings to fixed charges,
earnings consist of earnings from continuing operations before income taxes
and fixed charges (exclusive of interest capitalized). Fixed charges
consist of interest on all indebtedness (including amounts capitalized),
amortization of debt issuance costs and the portion of lease rental expense
that represents a reasonable approximation of the interest factor.
(2) The ratio of earnings to fixed charges was negative for the year ended
December 31, 1999. The amount of the coverage deficiency was $1,140
million.
10
As of December 31, As of
-------------------------------------------------- June 30,
1996 1997 1998 1999 2000 2001
----------- ----------- ----------- ------ ------- -----------
(unaudited) (unaudited) (unaudited) (unaudited)
Balance Sheet Data ( in
millions):
Cash and cash
equivalents............ $ 149 $ 301 $ 168 $ 228 $ 738 $ 801
Other current assets.... 602 1,926 2,577 1,897 5,382 4,464
------ ------ ------- ------ ------- -------
Total current assets.. 751 2,227 2,745 2,125 6,120 5,265
------ ------ ------- ------ ------- -------
Property, plant and
equipment, net......... 1,220 3,215 4,962 4,054 3,640 3,864
Other noncurrent
assets................. 890 1,436 2,440 1,887 3,346 2,828
------ ------ ------- ------ ------- -------
Total assets.......... $2,861 $6,878 $10,147 $8,066 $13,106 $11,957
====== ====== ======= ====== ======= =======
Total current
liabilities............ $ 505 $2,032 $ 2,878 $2,396 $ 5,833 $ 4,770
Long-term debt.......... 715 1,563 1,955 1,805 1,390 2,104
Other long-term
liabilities............ 409 894 2,514 1,983 3,504 2,643
------ ------ ------- ------ ------- -------
Total liabilities..... 1,629 4,489 7,347 6,184 10,727 9,517
------ ------ ------- ------ ------- -------
Preferred stock of
subsidiary and minority
interests.............. 92 96 81 78 75 77
Stockholder's equity.... 1,140 2,293 2,719 1,804 2,304 2,363
------ ------ ------- ------ ------- -------
Total liabilities and
stockholder's
equity............... $2,861 $6,878 $10,147 $8,066 $13,106 $11,957
====== ====== ======= ====== ======= =======
11
Six
Months
Ended
Year Ended December 31, June 30,
------------------------ ---------
1996 1997 1998 1999 2000 2000 2001
---- ---- ---- ---- ---- ---- ----
Other Data (in millions, unaudited):
Adjusted EBITDA(1).......................... $196 $267 $322 $396 $526 $237 $304
- --------
(1) Adjusted EBITDA is defined as income from continuing operations before
provision for income taxes, interest expense, depreciation and
amortization, including amortization of out-of-market contractual
obligations. Adjusted EBITDA excludes non-cash impairment charges and
write-offs. Adjusted EBITDA also includes all cash offset payments from NEP
related to our assumption of the purchase obligations under power purchase
agreements in our 1998 acquisition of our New England generating
facilities. Adjusted EBITDA is not intended to represent cash flows from
operations and should not be considered as an alternative to net income as
an indicator of our operating performance or as an alternative to cash
flows as a measure of liquidity. Refer to the Statement of Cash Flows for
the cash flows determined in accordance with generally accepted accounting
principles in the United States. We believe that Adjusted EBITDA is a
standard measure commonly reported and widely used by analysts, investors
and other interested parties. However, Adjusted EBITDA as presented in this
prospectus may not be comparable to similarly titled measures reported by
other companies. Adjusted EBITDA is composed of the following items (in
millions, unaudited):
Six
Months
Ended
Year Ended December 31, June 30,
------------------------------ ----------
1996 1997 1998 1999 2000 2000 2001
---- ---- ---- ------ ----- ---- ----
Income (loss) from continuing
operations........................ $ 8 $ 32 $ 3 $ (790) $ 192 $ 84 $125
Add:
Income tax expense (benefit)..... 30 (32) 41 (351) 130 55 82
Depreciation and amortization
expense......................... 52 99 167 214 143 70 75
Interest expense................. 46 81 156 162 155 78 58
Impairments and write-offs....... 60 87 -- 1,275 -- -- --
Amortization of out-of-market
contractual obligations......... -- -- (65) (181) (163) (84) (73)
Cash offset payments related to
NEP power supply agreements..... -- -- 20 67 69 34 37
---- ---- ---- ------ ----- ---- ----
Adjusted EBITDA as defined..... $196 $267 $322 $ 396 $ 526 $237 $304
==== ==== ==== ====== ===== ==== ====
12
RISK FACTORS
You should carefully consider the risks described below as well as other
information contained in this prospectus before exchanging your original notes.
If any of these events occur, our business, financial condition or results of
operations could be materially harmed, we may not be able to make payments on
the notes and you may lose all or part of your investment.
Risks Related to Our Relationship to PG&E Corporation
PG&E Corporation can exercise substantial control over our business and
operations and may do so in a manner that is adverse to our interests.
As a result of the "ringfencing" transactions previously described, our
independent director (and the independent director of the LLC) must approve
certain matters, including the payment of dividends, the disposition of a
substantial portion of our assets, and any merger or other business
combination. However, PG&E Corporation still has the right to initiate and seek
approval for these matters and has control over virtually all other matters
affecting us, including:
. the composition of our board of directors and, through it, any
determination with respect to our business and policies, including the
appointment and removal of officers (except that PG&E Corporation cannot
replace our "independent director" or the LLC's "independent director"
except with another person who is also "independent");
. the determination of incentive compensation, which may affect our ability
to retain key employees;
. the allocation of business opportunities between PG&E Corporation and us;
. determinations with respect to mergers or other business combinations;
. our acquisition or disposition of assets;
. our payment of dividends;
. decisions on our financings and our capital raising activities;
. the timing of repayment of various demand obligations between us and PG&E
Corporation;
. actions to comply with any order from the California Public Utilities
Commission;
. determinations with respect to our tax returns; and
. restrictions on our activities so as to comply with the terms of PG&E
Corporation's new credit agreement for its $1 billion term loans.
If PG&E Corporation defaults on its $1 billion credit facility, a "change in
control" of us could result, which would cause a default under certain of our
subsidiaries' credit agreements.
On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds under a credit agreement with General Electric
Capital Corporation and Lehman Commercial Paper, Inc., an affiliate of Lehman
Brothers Inc. Although we and our subsidiaries are not parties to, nor are we
bound by, the terms of the credit agreement, PG&E Corporation has given General
Electric Capital Corporation and Lehman Commercial Paper a security interest in
all of the LLC's outstanding membership interests. In addition, the LLC has
given the lenders a security interest in all of our outstanding capital stock.
If PG&E Corporation defaults on the credit agreement, the lenders could levy on
the pledge of our capital stock or the LLC's membership interests, which could
result in a change in control of us. A change in control of us could result in
a default under some of our subsidiaries' material agreements, which default
could lead to the downgrading of our credit ratings.
13
Claims could be made in the bankruptcy case of Pacific Gas and Electric Company
to substantively consolidate our assets and liabilities with those of Pacific
Gas and Electric Company; any such claim, if successful, would have a material
adverse effect on us and on our ability to repay the notes.
While it is an exception rather than the rule, especially where one of the
companies involved is not in bankruptcy, the equitable doctrine of substantive
consolidation permits a bankruptcy court to disregard the separateness of
related entities and to consolidate and pool the entities' assets and
liabilities and treat them as though held and incurred by one entity where the
interrelationship between the entities warrants such consolidation. On April 6,
2001, Pacific Gas and Electric Company, a direct subsidiary of our common
parent PG&E Corporation, filed a voluntary petition for relief under the
provisions of Chapter 11 of the U.S. Bankruptcy Code. Given the limited
interrelationship between us and Pacific Gas and Electric Company, we believe
that any effort to substantively consolidate us with Pacific Gas and Electric
Company would be without merit. However, we cannot assure you that no such
claims will be made in the bankruptcy case of Pacific Gas and Electric Company
or that we will be effectively insulated from such bankruptcy case. Any claim
to substantively consolidate us with Pacific Gas and Electric Company, if
successful, would have a material adverse effect on us and on our ability to
repay the notes.
Claims could be made in the Pacific Gas and Electric Company bankruptcy case
that we were the recipients of certain fraudulent transfers; any such claim, if
successful, could have a material adverse effect on us and on our ability to
repay the notes.
Section 548 of the U.S. Bankruptcy Code (and the similar provisions of
applicable state law, including the California Uniform Fraudulent Transfer Act)
permits a trustee or debtor in possession in a bankruptcy case (or a creditor)
to recover assets transferred by the debtor in certain circumstances. Assets
can be recovered if the transfer was made (i) with actual intent to hinder,
delay or defraud the debtor's creditors or (ii) for which the debtor received
less than reasonably equivalent value and the debtor (A) was or became
insolvent on the date of the transfer, (B) was engaged in a business for which
the remaining property was inadequate, or (C) intended by the transfer to incur
debts that would be beyond its ability to pay. Since our formation in 1998, our
parent, PG&E Corporation, has from time to time received intercompany payments
from its subsidiary, Pacific Gas and Electric Company, and has made capital
contributions to us. For example, during 2000, PG&E Corporation received
certain intercompany payments from Pacific Gas and Electric Company consisting
of:
. dividends on account of the capital stock of Pacific Gas and Electric
Company owned by PG&E Corporation;
. purchases by Pacific Gas and Electric Company of its stock from PG&E
Corporation;
. payments under certain shared services agreements and tax sharing
agreements to which Pacific Gas and Electric Company and PG&E Corporation
are parties; and
. repayments of short-term intercompany loans made by PG&E Corporation to
Pacific Gas and Electric Company for general corporate purposes from
January 1, 2000 through September 6, 2000.
During 2000, we received net capital contributions from PG&E Corporation of
$349 million, of which $204 million was received in the fourth quarter. Net
capital contributions represent the difference between the aggregate capital
contributions made by PG&E Corporation to us and the distributions made by us
to PG&E Corporation in the applicable period.
It is possible that claims may be made in the bankruptcy case of Pacific Gas
and Electric Company that some or all of the intercompany payments PG&E
Corporation has received from Pacific Gas and Electric Company since 1998
constituted voidable fraudulent transfers, and that some or all of the capital
contributions made by PG&E Corporation to us during the same period should be
recovered for the benefit of the estate of Pacific Gas and Electric Company. We
believe that any such claim would most likely focus on the intercompany
payments made during 2000. We believe that any claim against us attempting to
recover such intercompany payments would be premised on linking such
intercompany payments to the capital contributions
14
made to us by PG&E Corporation. Based on the information available to us, we
believe Pacific Gas and Electric Company was solvent, was able to pay its
reasonably foreseeable liabilities as they became due and was adequately
capitalized, both before and after making any intercompany payments to our
common parent since 1998, and that there was no actual intent to hinder, delay
or defraud creditors of Pacific Gas and Electric Company as a result of any
such payments. Accordingly, we believe any such claim would be without merit.
There can be no assurance, however, that such claims will not be made, that, if
made, they will be limited to 2000 or that we will be effectively insulated
from the pending bankruptcy case of Pacific Gas and Electric Company. Any claim
to recover all or any significant portion of such intercompany payments from
us, if successful, could have a material adverse effect on us and on our
ability to repay the notes.
The pending investigation by the California Public Utilities Commission may
adversely affect us.
On April 3, 2001, the California Public Utilities Commission, or the CPUC,
issued an order instituting an investigation into whether the California
investor-owned utilities and their holding companies, including Pacific Gas and
Electric Company and PG&E Corporation, have complied with past CPUC decisions,
rules and orders authorizing their holding company formations and/or governing
affiliate transactions, as well as applicable statutes. The order states that
the CPUC will investigate:
. the utilities' transfer of money to their holding companies since
deregulation of the electric industry commenced, including during times
when their utility subsidiaries were experiencing financial difficulties;
. whether the holding companies failed to financially assist the utilities
when needed;
. the transfer by the holding companies of assets to unregulated
subsidiaries, including capital contributions made by the holding
companies; and
. holding companies' actions to "ringfence" their unregulated subsidiaries.
On June 6, 2001, in response to motions filed by the affected holding
companies (including PG&E Corporation) to dismiss the investigation against
them for lack of subject matter jurisdiction, a CPUC administrative law judge
issued for comment a draft decision denying the motions. A revised draft
decision, reaching the same conclusion, was issued on July 12, 2001. The
revised draft decision concludes, among other matters, that "regulatory
doctrine allows the Commission to ignore corporate form and reach the assets
and conduct of all entities within the system--and the prerequisites to common-
law veil piercing need not be met." On July 19, 2001, CPUC Commissioner
Henry Duque issued an alternate draft decision granting the motions to dismiss.
The drafts are currently scheduled to be before the CPUC for decision on August
23, 2001. We are not a party to this investigatory proceeding. We cannot
predict whether, when or in what form a decision will be adopted, or what
direct or indirect effects any subsequent action taken by the CPUC in such
proceeding or in any other action or proceeding, in reliance on the principles
articulated in this revised draft decision and in other applicable authority,
may have on us and our ability to meet our obligations under the notes.
We are a member of a consolidated group and we may be liable for the taxes of
other members of the group.
We are a member of the consolidated income tax group that includes PG&E
Corporation and its includible domestic subsidiary corporations, one of which
is Pacific Gas and Electric Company. We could be held responsible for income
tax liabilities of PG&E Corporation or Pacific Gas and Electric Company if
PG&E Corporation or Pacific Gas and Electric Company were unable to satisfy
those liabilities.
15
Risks Associated with Our Business
We are a holding company, which means that our access to the cash flow of our
subsidiaries may be limited and your right to receive payment on the notes is
effectively junior to existing debt and all obligations of our subsidiaries and
project affiliates.
We are a holding company, with no direct operations and no assets other than
the stock of our subsidiaries. As a result, we depend entirely upon the
earnings and cash flow of our subsidiaries and project affiliates to meet our
obligations, including the payment of principal of and interest on the notes.
If these entities are unable to provide cash to us when we need it, we will be
unable to meet these obligations. Many of our subsidiaries and project
affiliates have their own debt, the terms of which may restrict payments of
dividends and other distributions. In many cases, the loan, partnership and
other agreements that apply to our project affiliates restrict them from
distributing cash unless, among other things, debt service, lease obligations
and any applicable preferred payments are current, the project meets certain
debt service coverage ratios, a majority of the participants in the project
agree that distributions should be made, and there are no events of default.
In addition, the subsidiaries that own our natural gas transmission
facilities and our energy trading businesses have been "ringfenced" and may not
pay dividends to us unless the applicable subsidiary's board of directors or
board of control, including its independent director, unanimously approves the
dividend and unless the subsidiary either has a specified investment grade
credit rating or meets a 2.25 to 1.00 consolidated interest coverage ratio and
a 0.70 to 1.00 consolidated leverage ratio. The exchange notes, like the
original notes, will be solely our obligation. Our subsidiaries are separate
legal entities that will have no obligation to pay any amounts due under the
notes or to make any funds available for payment of amounts due under the
notes.
The notes are structurally subordinated to the indebtedness and other
obligations of our subsidiaries. In the event of any insolvency, bankruptcy,
liquidation or similar event with respect to any of our subsidiaries, the
assets in that subsidiary will be available to pay obligations under the notes
only after all claims of that subsidiary's creditors, including trade
creditors, have been paid in full.
Our activities are restricted by the substantial indebtedness of our
subsidiaries; a subsidiary's inability to service its indebtedness could
adversely affect our financial condition.
At June 30, 2001, our consolidated subsidiaries had aggregate indebtedness
of approximately $2.0 billion. Most of this debt is secured by the facilities
of the applicable project or other subsidiary assets and any default on such
debt could lead to the loss of the project or other assets securing the debt.
In addition to restricting or prohibiting dividends, these debt agreements
often limit or prohibit our subsidiaries' ability to:
. incur indebtedness;
. make prepayments of indebtedness in whole or in part;
. make investments;
. engage in transactions with affiliates;
. create liens;
. sell assets; and
. acquire facilities or other businesses.
If our subsidiaries are unable to comply with the terms of their debt
agreements, they may be required to refinance all or a portion of their debt or
obtain additional financing. Our subsidiaries may be unable to refinance or
obtain additional financing because of their high levels of debt and the debt
incurrence restrictions under their debt agreements. They also may default on
their debt obligations if cash flow is insufficient. If any subsidiary defaults
under the terms of its indebtedness, the debt holders may, in addition to other
remedies they may have, accelerate the maturity of our subsidiary's
obligations, which could cause cross-defaults or cross-acceleration under other
obligations and could adversely affect our financial condition.
16
We have a substantial amount of indebtedness, including short-term
indebtedness, which indebtedness could limit our ability to finance the
acquisition and development of additional projects.
As of June 30, 2001, we had short-term debt of $754 million (including debt
to PG&E Corporation) and long-term borrowings of $2.2 billion (excluding the
debt of project affiliates accounted for under the equity method). These
amounts reflect the issuance of the original notes and the application of the
proceeds of their sale. The indenture governing the notes does not impose
limitations on our ability or the ability of our subsidiaries to incur
additional indebtedness. Our substantial amount of debt and financial
obligations presents the risk that we might not have sufficient cash to service
our indebtedness, including the notes, and that our existing corporate and
project debt could limit our ability to finance the acquisition and development
of additional projects, to compete effectively or to operate successfully under
adverse economic conditions.
We maintain various revolving credit facilities at subsidiary levels which
currently are available to fund our capital and liquidity needs. Our generation
operation maintains one $500 million revolving credit facility, one $550
million revolving credit facility and one $100 million revolving credit
facility. The $500 million facility expires at the end of August 2001 (but may
be extended for up to two years or until our new facility is increased) and the
$550 million facility expires in August 2003. The $100 million facility expires
in September 2003. GTN maintains a $100 million revolving credit facility that
expires in May 2002 (but may be extended for successive one-year periods). As
of June 30, 2001, we had borrowed $520 million against our total $1.25 billion
borrowing capacity under these facilities. In addition, as of June 30, 2001
approximately $33 million of letters of credit were outstanding under these
facilities, reducing the remaining borrowing capacity available.
On May 29, 2001, we established a revolving credit facility of up to $280
million to fund turbine payments and equipment purchases associated with our
generation facilities. Borrowings from this facility were used to purchase all
turbines from our two master turbine trusts. This facility expires on December
31, 2003.
We also recently established a $550 million revolving credit facility (which
includes the ability to issue letters of credit) to support our energy trading
operations and for other working capital requirements. As of June 30, 2001,
approximately $111 million of letters of credit were outstanding under this
facility and there were no borrowings under this facility. We are planning to
increase this facility to $1.25 billion by the end of 2001 and to terminate the
$500 million and the $550 million facilities at our generation operation. This
new $550 million facility has an initial 364-day term that expires on June 14,
2002. Upon increase, we expect a portion of this facility will have a 364-day
term and a portion will have a two-year term. These portions may be structured
as separate facilities. This facility is one of our senior unsecured
obligations and ranks equally with the notes.
We cannot assure you that we will be able to extend our existing credit
facilities or obtain new credit facilities to finance our needs, or that any
new credit facility can be obtained under similar terms and rates as our
existing credit facilities. If we cannot extend our existing credit facilities
or obtain new credit facilities to finance our needs on similar terms and rates
as our existing credit facilities, this could have a negative impact on our
liquidity and on our ability to make debt service payments on the notes.
Our ability to manage commodity price fluctuations may be limited due to
conditions in western electric markets and our affiliation with PG&E
Corporation and Pacific Gas and Electric Company.
To lower our financial exposure related to commodity price fluctuations, we
routinely enter into contracts to hedge purchase and sale commitments, weather
conditions, fuel requirements and supplies of natural gas, coal, electricity,
crude oil and other commodities. As part of this strategy, we use fixed-price
forward physical purchase and sales contracts, futures, financial swaps, option
contracts and other hedging arrangements. Due, in part, to the increased price
volatility in the western electricity and gas markets, there has been a
decrease in the liquidity of the trading markets and the combination of
increased volatility and decreased liquidity has reduced our ability to hedge
and/or liquidate our positions. In addition, various trading counterparties
have limited the amount of open credit they will extend to us and we have been
required to post additional collateral with our counterparties as a result of
price volatility in the market. While this has been an industry-wide
phenomenon, we have been more affected by it than others because of
counterparties' concerns about the financial condition
17
of PG&E Corporation and Pacific Gas and Electric Company. There can be no
assurance that we will be able to use hedging transactions effectively to lower
our financial exposure to commodity price fluctuations, or that we will be able
to post the security that our counterparties may request.
Commodity price fluctuations, volatility and other market conditions may
adversely affect our financial performance.
We buy natural gas, fuel oil and coal to supply the fuel to generate
electricity at our facilities. Our financial results would be adversely
affected if the cost of the fuel that we must buy to generate electricity
increases to a greater degree than the price that we can obtain for the
electricity that we sell. As we continue the development and construction of
our merchant power generation projects, a greater percentage of our revenues
will become subject to this commodity price risk. The prices of the commodities
that we use and sell in our businesses are subject to extreme volatility. This
volatility may result from many factors, many of which are beyond our control,
including:
. weather;
. the supply and demand for energy commodities;
. the availability of competitively priced alternative energy sources;
. the level of production and availability of natural gas, crude oil and
coal;
. transmission or transportation constraints;
. federal and state energy and environmental regulation and legislation;
. illiquid energy markets; and
. natural disasters, wars, embargoes and other catastrophic events.
Changes in any of these factors may increase our costs of producing power or
decrease the amount we receive from the sale of power, which would adversely
affect our financial results.
Despite our hedging positions and risk management policies and procedures, we
may be exposed to unidentified or unanticipated risks which could result in
significant losses.
Our uncovered trading positions expose us to the risk that fluctuating
market prices may adversely affect our financial results. Although our
uncovered positions are limited by our risk management policies, including
stop-loss limits and limits on value-at-risk and notional open positions, the
success of the risk management methods that we use depends upon our proper
evaluation of information regarding markets, clients or other matters that is
publicly available or otherwise accessible by us. In addition, the success of
our risk management depends on the accuracy of our own assumptions regarding
price volatility, market liquidity and holding periods. If the information we
use is not accurate, complete, up-to-date or properly evaluated, or our
assumptions are incorrect, our risk management methods may not be effective and
we may experience significant losses.
In addition, our risk management methods have certain inherent limitations,
including underestimation of the risk of a portfolio with significant options
exposure, inadequate indication of the exposure of a portfolio to extreme price
movements and the inability to address the risk resulting from intra-day
trading activities. Furthermore, no set of policies and procedures, even if
well implemented, can fully insulate us from exposure to changes in value in
volatile commodity markets, particularly with respect to our uncovered trading
positions.
Our credit ratings could be downgraded, which would have adverse effects on
many aspects of our business.
Following the bankruptcy filing by Pacific Gas and Electric Company,
Standard & Poor's affirmed our "BBB" corporate credit rating on April 6, 2001
and Moody's affirmed our "Baa2" corporate credit rating on
18
April 9, 2001. Although our credit ratings remain investment grade, the
downgrading of our credit ratings below investment grade would increase our
cost of capital, make efforts to raise capital more difficult and have an
adverse impact on us and our subsidiaries.
Under the guarantees issued to support Lake Road, La Paloma and Harquahala,
as well as our new $280 million equipment purchase revolving credit facility,
if we were downgraded below investment grade, we would be required to provide
alternative credit enhancements, such as guarantees of our investment grade
subsidiaries, letters of credit or cash collateral. If we were unable to
provide such enhancements within 30 days, the guaranteed loans would be due and
payable within five days. If such loans were not repaid within this period, the
lenders to those projects would have the right to stop lending under the
applicable financing agreement, we would be required to repay all the loans and
the lenders could foreclose on the project assets and call on our guarantees.
In addition, if we were unable to perform under those guarantees, we could be
in default under all of our senior obligations, including the notes, which
could materially harm our business.
Moreover, we or various of our subsidiaries have guaranteed the financial
performance of our energy trading subsidiaries to various trading
counterparties. If we fall below an investment grade rating, alternative
security would have to be posted in the form of other investment grade
guarantees, letters of credit or cash collateral. If we were unable to provide
such enhancements, certain valuable contractual assets could be lost and
certain trading obligations could be accelerated, which could materially harm
our business.
Increased competition in our industry may adversely affect our operating
results.
As a result of the ongoing restructuring of our industry, our integrated
generation and energy marketing and trading businesses are experiencing
increased competition with other electric generators, marketers and brokers.
Our ability to compete effectively is influenced by numerous factors, including
the extent of restructuring in key markets, the activities and resources of our
competitors, and market prices and conditions, including market liquidity. As
pricing information becomes increasingly available in the energy marketing and
trading business and as deregulation in the electricity markets continues to
evolve, we anticipate that our energy marketing and trading operations will
experience greater competition and downward pressure on per-unit profit
margins. Our natural gas transmission business competes with other pipeline
companies, marketers and brokers, as well as producers who are able to sell
natural gas directly into the wholesale end-user markets. The ability of our
gas transmission business to compete effectively is influenced by numerous
factors, including regulatory conditions and the supply of and demand for
pipeline and storage capacity. There can be no assurance that we will be able
to compete effectively. Our failure to compete effectively may adversely impact
our operating results and our ability to grow.
If a major supplier or customer fails to perform its obligations, our financial
results and our ability to make payments on the notes could be adversely
impacted.
Some of our subsidiaries depend on only one or a few suppliers and
customers. The financial performance of our subsidiaries depends on the
continued performance and credit quality of these suppliers and customers. For
example, 13 of our 23 operating generating facilities rely on a small number of
suppliers to provide all or a significant portion of their fuel and a small
number of customers to purchase all or a significant portion of their output.
In addition, a significant portion of the revenues generated from our gas
transmission business is based on long-term contracts with a limited number of
customers. A subsidiary's financial results could be materially adversely
affected if any major supplier or customer fails to fulfill its contractual
obligations, particularly if the subsidiary would have to procure services or
sell products at a current market price that is significantly worse than the
contracted price. If a major supplier or customer fails to comply with its
contractual obligations, the affected subsidiary may be unable to repay
obligations under its debt, which may have a negative impact on our financial
condition and our ability to make payments on the notes.
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Our revenue may be reduced significantly upon the expiration or termination of
one or more of our standard offer agreements or other power sales agreements.
A substantial portion of the electricity we generate from our generating
facilities is sold under wholesale standard offer agreements and other power
sales agreements that expire at various times. When these agreements expire the
price paid to us for the electric output and capacity may be reduced
significantly if the then-prevailing market price is below the contractual
rate, which could substantially reduce our revenue. For example, our
subsidiaries have entered into wholesale standard offer agreements with retail
companies of the New England Electric System to supply the electric capacity
and energy requirements necessary for these retail companies to meet their
obligations to provide service to those customers who elect not to use an
alternative energy supplier. These wholesale standard offer agreements resulted
in revenues to us of $587 million during 1999 and $563 million during 2000. The
wholesale standard offer agreement for Massachusetts customers expires on
December 31, 2004 and the standard offer agreement for Rhode Island customers
expires on December 31, 2009. In addition, retail customers may elect to use an
alternative energy supplier at any time, reducing the volume of power we sell
under these agreements. There can be no assurance that to the extent retail
customers elect to use alternative energy suppliers or once the wholesale
standard offer agreements expire we will be able sell our output at comparable
prices.
Our financial results may be adversely impacted if we are unable to manage the
risks inherent in operating our generating and pipeline facilities.
The operation of our generating and pipeline facilities involve numerous
risks, including poor equipment performance, equipment failure, errors in
operation, labor issues, accidents, natural disasters, and interruptions or
constraints in the operation of critical external systems or activities such as
electric transmission or fuel supply. The occurrence of any of these events
could result in lost revenues or increased expenses that may not be fully
covered in a timely fashion by contractual commitments or insurance which may
adversely impact our operating results.
We have experienced technological problems with some of the new turbines used
at our generating facilities and these problems have adversely impacted our
ability to complete these facilities on schedule.
We have secured contractual commitments and options for technologically
advanced generating turbines that are designed to provide higher output using
less fuel than older designs. These turbines have limited operating histories
and may perform at levels below our expectations or take longer to achieve the
specified levels of performance. Technological problems with these turbines or
the failure of these turbines to operate at design output and heat rate may
delay the development of our new generating facilities or may result in lower
than projected revenues from these facilities, both of which events may
adversely impact our operating results.
For example, Alstom Power, Inc. has advised us that it may take up to three
years to develop and implement modifications to its turbines that are necessary
to achieve the guaranteed level of efficiency and output. We expect that our
Lake Road and La Paloma facilities that are currently under construction by
Alstom will begin commercial operations at reduced performance and output
levels because of the technology issues with Alstom's turbines. We also
encountered start-up problems with the Siemens Westinghouse turbine installed
in our Millennium facility that delayed the commercial operation of this
facility for several months.
Our integrated generation and energy marketing and trading business operates in
the deregulated segments of the electric power industry. If the present trend
toward 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 applicable to the electric power industry has
recently undergone substantial changes as a result of restructuring initiatives
at both the state and federal levels. These initiatives have had a significant
impact on the nature of the industry and the manner in which its participants
conduct their business.
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We compete and operate in the deregulated segments of the electric power
industry created by these initiatives. These changes are ongoing and we cannot
predict the future development of deregulation in these markets or the ultimate
effect that this changing regulatory environment will have on our business.
Moreover, existing regulations may be revised or reinterpreted or we may become
subject to new laws and future regulations which could have a detrimental
effect on our business. In some of our markets, including California, proposals
have been made by governmental agencies and/or other interested parties to re-
regulate areas of these markets which have previously been deregulated. In
other markets, particularly the western states, legislative or administrative
actions may delay the impact of restructuring. We cannot assure you that other
proposals to re-regulate or halt deregulation plans will not be made or that
legislative or other attention to the electric restructuring process will not
cause the process to be delayed or reversed. If the current trend towards
competitive restructuring of the wholesale and retail power markets is
reversed, discontinued or delayed, our business prospects and financial
condition could be materially adversely affected.
Many of our activities are subject to rate regulation and changes in this
regulation may affect the rates we are able to charge.
FERC has approved on a temporary basis the imposition of price caps and
market mitigation plans restricting the amount that can be charged by
electricity generators and marketers in particular markets, such as measures
recently approved for the California, New York and New England markets. Certain
states, for example New York and California, also have proposed such price
caps. On July 25, 2001, FERC ordered that refunds may be due from sellers who
engaged in transactions in the California markets between October 2, 2000 and
June 20, 2001, including PG&E Energy Trading-Power, or ET-Power. In connection
with the FERC proceeding, on August 17, 2001, the California ISO submitted data
indicating that ET-Power may be required to refund approximately $26 million.
Using what we believe to be the same methodology (including pricing information
provided by the California ISO), we believe that the amount of the refund owed
by ET-Power, excluding offsets, is significantly less. The methodology and its
implementation by the California ISO remain subject to FERC proceedings. Given
this uncertainly and the fact that we are reconciling these computations with
the California ISO, management is currently unable to determine the amount that
may ultimately be determined to be due. In addition, FERC has indicated that
unpaid amounts owed by the California ISO and the California Power Exchange may
be used as offsets to any refund obligations. We estimate that ET-Power is
currently owed approximately $22 million that could be used as an offset to any
potential refund obligation. Finalization of all these amounts will be subject
to the ongoing FERC proceeding.
FERC has also instituted a separate procedure to evaluate the potential for
refunds in the Pacific Northwest region. These types of initiatives could have
an adverse impact on our financial performance.
Ten of our generating facilities are exempt wholesale generators, or EWGs,
that sell electricity exclusively into the wholesale market at market-based
rates pursuant to authority granted by the Federal Energy Regulatory
Commission, or FERC. If FERC concludes that the market is not workably
competitive or that market-based rates in a particular market are not just and
reasonable, it has the authority to impose "cost of service" rate regulation on
EWGs. The change from market-based rates to cost-based rates could adversely
affect the rates we are able to charge.
The Public Utility Regulatory Policies Act of 1978, or PURPA, provides to
qualifying facilities (as defined under PURPA), or QFs, and owners of QF
exemptions from certain federal and state regulations, including rate and
financial regulations. Eleven of our generating facilities are QFs. Should any
of these plants in which we have an interest lose their QF status or if
amendments to PURPA are enacted that substantially reduce the benefits
currently afforded existing QFs, we could become a public utility holding
company, which could subject us to significant rate regulation and which could
adversely affect our other QFs. In addition, it is possible for a facility to
lose its QF status through operational or ownership changes. Loss of QF status
could, depending on the particular power sales agreement, allow the power
purchaser to terminate the power sales agreement with the facility, thereby
causing the loss of some or all revenues under the power sales agreement or
otherwise impairing the value of the generating facility. The United States
Congress is considering
21
legislation which would repeal PURPA or at least eliminate the obligation of
utilities to purchase power from new QFs. We cannot predict the full scope or
effect of this type of legislation, although we anticipate that any legislation
would result in increased competition.
FERC, pursuant to the Natural Gas Act, regulates the tariff rates for our
interstate pipeline operations. To be lawful under the Natural Gas Act, tariff
rates must be just and reasonable and not unduly discriminatory. Shippers may
protest, and FERC may investigate, the lawfulness of tariff rates. If the rates
we are permitted to charge our customers for use of our regulated pipelines are
lowered, the profitability of our natural gas transmission business may be
reduced.
FERC has issued electricity and natural gas transmission initiatives that
require electric and gas transmission services to be offered on a common
carrier basis unbundled from commodity sales. Although these initiatives are
designed to encourage wholesale market transactions for electricity and natural
gas, there is the potential that fair and equal access to transmission systems
will not be available and we cannot predict the timing of industry changes as a
result of these initiatives, or the adequacy of transmission additions in
specific markets. FERC has also begun regulatory initiatives to encourage the
establishment of independent system operators and regional transmission
organizations.
Many of our activities and properties are subject to environmental requirements
and changes in, or liabilities under, these requirements may adversely affect
our profitability.
Our operations are subject to extensive federal, state and local statutes,
rules and regulations relating to environmental protection. To comply with
these legal requirements, we must spend significant sums on environmental
monitoring, pollution control equipment, emission fees and other compliance
work. In addition, compliance with such laws and regulations might result in
restrictions on some of our operations. We may be exposed to compliance risks
for our operating generating and other facilities, as well as those under
construction or in development. If we do not comply with environmental
requirements that apply to our operations, regulatory agencies could seek to
impose on us civil, administrative and/or criminal liabilities, as well as seek
to curtail our operations. Under some statutes, private parties could also seek
to impose civil fines or liabilities for property damage, personal injury and
possibly other costs. We cannot assure you that lawsuits or other
administrative actions against our generating facilities will not be filed or
taken in the future. If an action is filed against us or our generating
facilities, this could require substantial expenditures to bring our generating
facilities into compliance and have a material adverse effect on our financial
condition, cash flows and results of operations.
We expect our environmental expenditures to remain substantial in the
future. Stricter standards, greater regulation, increased enforcement by
regulatory authorities, more extensive permitting requirements and an increase
in the number and types of assets operated by us subject to environmental
regulation may increase these expenditures. Although the scope and extent of
new environmental regulations, permitting requirements and enforcement
initiatives, including their effect on our operations, is unclear, they could
materially increase our cost or limit the operation of some of our facilities.
For example, the U.S. Environmental Protection Agency, or EPA, has recently
promulgated more stringent air quality standards for particulate matter emitted
from generating facilities and is currently considering new permit requirements
to address thermal discharges in cooling water from generating facilities. In
addition, the EPA recently has commenced enforcement actions against a number
of electric utilities, several of which have entered into substantial
settlements, for alleged Clean Air Act violations related to modifications
(sometimes more than 20 years ago) of existing coal-fired generating
facilities. We have not received a notice of violation or other enforcement
action along these lines. However, the EPA has requested that we submit
information to it relating to some of our coal-fired generating facilities of
the type that could be relevant to such enforcement action.
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The states in which we operate facilities may impose additional
environmental requirements. Recently the Commonwealth of Massachusetts issued
new regulations that impose more stringent air emission limitations on
generating facilities located in that jurisdiction and we expect to be subject
to more stringent water discharge requirements. These new requirements affect
our Brayton Point and Salem Harbor generating facilities. Although only
preliminary, our current estimate is that these new regulations and
requirements may require us to spend approximately $325 million through 2006.
Some federal and state environmental laws generally impose liability for
the investigation and cleanup of contaminated soil, groundwater, and other
environmental media, and for damages to natural resources, on a wide range of
entities that have some relationship to the contamination. These may include,
for example, former owners or operators of a contaminated property and those
who arranged for disposal of the contaminants, as well as the current owner or
operator of such property. Generally, liability may be imposed even though the
conduct that caused the environmental condition was lawful at the time it
occurred. Such liability may also be imposed jointly and severally (that is,
with each entity subject to full responsibility for the liability involved,
even though there were others who contributed). In addition, environmental
contamination and other environmental conditions can result in claims for
personal injury, property damages, and/or punitive damages. We own or operate
properties, and there are also other properties, at which contamination exists
that could result in liability affecting us.
Our project development and acquisition activities may not be successful,
which would impair our ability to pursue our growth strategy.
Our businesses involve numerous risks relating to the development and
acquisition of energy assets. We may not be able to identify attractive
development or acquisition opportunities or complete development or
acquisition projects that we undertake. If we are not able to identify and
complete development or acquisition projects, we will not be able to
successfully execute our growth strategy. In addition, the success of our
future development and acquisition projects will depend, in part, on our
ability to acquire or develop them on favorable terms. We often incur
substantial expenses in investigating and evaluating a potential development
or acquisition opportunity before we can determine whether the opportunity is
feasible or economically attractive.
Factors that may adversely impact our development and acquisition
activities and growth strategy include:
. our ability to obtain capital to develop or acquire energy assets on
acceptable terms while preserving our credit quality;
. competition among potential acquirers and other developers;
. our ability to obtain required governmental permits and approvals;
. the availability of suitable sites and equipment at reasonable prices;
. cost overruns or delays in development as a result of labor issues,
regulatory delays or restrictions, or other unanticipated events;
. new technology and unforeseen engineering issues;
. our ability to negotiate acceptable acquisition, construction, fuel
supply or other material agreements;
. the ability of third parties to develop, finance, construct and operate
facilities that we contractually control;
. the regulatory environment, including the pace of restructuring, re-
regulation (e.g., the imposition of price caps or cost-of-service
regulation) and the structure of the market in which the asset is to be
located;
. changes in fuel and electricity prices and our ability to manage these
changes;
. transmission, transportation or other constraints stemming from the
actions or failures to act by third parties that impact our ability to
grow;
23
. changes in accounting treatment of contractual control arrangements; and
. our ability to anticipate and respond to the demands on our systems,
procedures, workforce and structures resulting from our growth strategy.
Any of these factors could give rise to delays, cost overruns or the
termination of our development or construction projects. These factors could
also adversely impact or result in the termination of planned acquisitions of
projects or the development or construction of projects by others that we
contractually control. We may not complete planned development or construction
projects within our projected time schedules or budgets. For example, we are
currently experiencing construction delays in connection with the construction
of the Lake Road and La Paloma facilities. Furthermore, we may not enter into
or retain all of the agreements necessary for us to achieve our anticipated
contractual control over generating facilities. If we are unable to complete
the development of a generating facility or pipeline, or achieve contractual
control over an energy asset, we may incur additional costs, liquidated
damages, or termination of other project contracts, and we may be unable to
recover any previous investment in the project. In addition, construction
delays and contractor performance shortfalls result in the loss of revenues and
may, in turn, adversely affect our results of operations. The failure to
complete construction according to specifications can result in liabilities,
reduced efficiency, higher operating costs and reduced earnings.
If we fail to attract and retain key personnel, our business will be materially
and adversely affected.
We depend on the continued services of our key senior management personnel,
including Thomas G. Boren, our President and Chief Executive Officer, P.
Chrisman Iribe, our President and Chief Operating Officer for the Eastern
Region, Thomas B. King, our President and Chief Operating Officer for the
Western Region, and Lyn Maddox, our President and Chief Operating Officer of
Trading. Any officer or employee can terminate his or her relationship with us
at any time. The loss of any of our key personnel or our inability to attract,
train, retain and motivate additional qualified management and other personnel
could have a material adverse effect on our business. Competition for these
personnel is intense and there can be no assurance that we will be successful
in this regard. The uncertainty regarding the financial status of PG&E
Corporation, the recent bankruptcy filing by Pacific Gas and Electric Company
and the negative impact that these events have had on us has negatively
affected the morale of some of our employees and has resulted in employee
attrition.
Risks Related to the Notes
The exchange notes have no prior public market and we cannot assure you that
any public market will develop or be sustained after the offering.
Although the exchange notes generally may be resold or otherwise transferred
by holders who are not our affiliates without compliance with the registration
requirements under the Securities Act, they will constitute a new issue of
securities without an established trading market. We have been advised by the
initial purchasers that they currently intend to make a market in the
registered notes. However, there can be no assurance that such a market will
develop or, if it does develop, that it will continue. In addition, any such
market-making activity may be limited during the exchange offer and during the
pendency of any shelf registration that might be filed. If an active public
market does not develop, the market price and liquidity of the exchange notes
may be adversely affected. Furthermore, we do not intend to apply for listing
of the exchange notes on any securities exchange or automated quotation system.
Even if a market for the exchange notes does develop, you may not be able to
resell the exchange notes for an extended period of time, if at all. In
addition, future trading prices for the exchange notes will depend on many
factors, including, among other things, prevailing interest rates, our
financial condition, and the market for similar securities. As a result, you
may not be able to liquidate your investment quickly or to liquidate it at an
attractive price.
24
You may have difficulty selling the original notes which you do not exchange.
If you do not exchange your original notes for the notes offered in this
exchange offer, you will continue to be subject to the restrictions on the
transfer of your original notes. Those transfer restrictions are described in
the indenture and in the legend contained on the original notes, and arose
because we issued the original notes under exemptions from, and in transactions
not subject to, the registration requirements of the Securities Act. In
general, you may offer or sell your original notes only if they are registered
under the Securities Act and applicable state securities laws, or if they are
offered and sold under an exemption from those requirements. If you do not
exchange your original notes in the exchange offer, you will no longer be
entitled to have those notes registered under the Securities Act.
In addition, if a large number of original notes are exchanged for notes
issued in the exchange offer, the principal amount of original notes that will
be outstanding will decrease. This will reduce the liquidity of the market for
the original notes, making it more difficult for you to sell your original
notes.
The notes may not retain their ratings.
Moody's and Standard & Poor's have assigned ratings to the exchange notes of
"Baa2" and "BBB," respectively, the same ratings assigned to the original
notes. A rating is not a recommendation to purchase, hold or sell the notes,
because a rating does not address market price or suitability for a particular
investor. There can be no assurance that a rating will remain in effect for any
given period of time or that a rating will not be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant.
In addition, if our credit ratings are reduced, the ratings on the notes are
likely to be correspondingly reduced.
Broker-dealers or noteholders may become subject to the registration and
prospectus delivery requirements of the Securities Act.
Any broker-dealer that:
. exchanges its original notes in the exchange offer for the purpose of
participating in a distribution of the exchange notes; or
. exchanges original notes that were received by it for its own account in
the exchange offer,
may be deemed to have received restricted securities and may be required to
comply with the registration and prospectus delivery requirements of the
Securities Act in connection with any resale transaction by that broker-dealer.
Any profit on the resale of the exchange notes and any commission or
concessions received by a broker-dealer may be deemed to be underwriting
compensation under the Securities Act.
In addition to broker-dealers, any noteholder that exchanges its original
notes in the exchange offer for the purpose of participating in a distribution
of the exchange notes may be deemed to have received restricted securities and
may be required to comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale transaction by
that noteholder.
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USE OF PROCEEDS
We will not receive any proceeds in connection with the exchange offer. In
consideration for issuing the exchange notes in exchange for the original notes
as described in this prospectus, we will receive, retire and cancel the
original notes. The net proceeds from the sale of the original notes, after
deducting discounts, commissions and offering expenses, were approximately $974
million. We used $630 million to pay down our revolving credit facilities, and
will use the remainder of the net proceeds to pay the approximately $90 million
purchase price for our Mountain View wind facility, fund working capital
requirements, make investments in generating and pipeline assets, or for other
general corporate purposes.
26
THE EXCHANGE OFFER
Purpose of the Exchange Offer
We issued and sold the original notes on May 22, 2001 in a private
placement. In connection with that issuance and sale, we entered into a
registration rights agreement with the initial purchasers of the original
notes. In the registration rights agreement, we agreed to:
. file with the SEC the registration statement of which this prospectus is
a part within 180 days of the issue date of the original notes relating
to an offer to exchange the original notes for the exchange notes;
. use our reasonable best efforts to cause the registration statement of
which this prospectus is a part to be declared effective under the
Securities Act; and
. commence the exchange offer and keep the exchange offer open for at least
30 days after the date of this prospectus.
The exchange offer being made by this prospectus is intended to satisfy our
obligations under the registration rights agreement. If we fail to exchange all
validly tendered original notes in accordance with the exchange offer on or
prior to March 18, 2002, we will be required to pay additional interest to
holders of original notes until we have complied with this obligation.
Once the exchange offer is complete, we will have no further obligation to
register any of the original notes not tendered to us in the exchange offer,
except to the limited extent that certain qualified institutional buyers, if
any, are otherwise entitled to have their original notes registered under a
shelf registration as described under "Description of the Notes--Registration
Rights Agreement." For a description of the restrictions on transfer of the
original notes, see "Risk Factors--Risks Related to the Notes."
Effect of the Exchange Offer
Based on interpretations by the SEC staff set forth in Exxon Capital
Holdings Corporation (available April 13, 1989), Morgan Stanley & Co.
Incorporated (available June 5, 1991), Shearman & Sterling (available July 7,
1993) and other no-action letters issued to third parties, we believe that you
may offer for resale, resell and otherwise transfer the exchange notes issued
to you in the exchange offer without compliance with the registration and
prospectus delivery requirements of the Securities Act if:
. you are acquiring the exchange notes in the ordinary course of your
business and do not hold any original notes to be exchanged in the
exchange offer that were acquired other than in the ordinary course of
business;
. you are not a broker-dealer tendering original notes acquired directly
from us;
. you are not participating, do not intend to participate and have no
arrangements or understandings with any person to participate in the
exchange offer for the purpose of distributing the exchange notes; and
. you are not our "affiliate," within the meaning of Rule 405 under the
Securities Act.
If you are not able to meet these requirements, you are a "restricted
holder." As a restricted holder, you will not be able to participate in the
exchange offer, you may not rely on the interpretations of the SEC staff set
forth in the no-action letters referred to above and you may only sell your
original notes in compliance with the registration and prospectus delivery
requirements of the Securities Act or under an exemption from the registration
requirements of the Securities Act or in a transaction not subject to the
Securities Act.
We do not intend to seek our own no-action letter, and there can be no
assurance that the staff of the SEC would make a similar determination with
respect to the exchange notes as it has in such no-action letters to third
parties.
27
In addition, if the tendering holder is a broker-dealer that will receive
exchange notes for its own account in exchange for original notes that were
acquired as a result of market-making activities or other trading activities,
it may be deemed to be an "underwriter" within the meaning of the Securities
Act. Any such holder will be required to acknowledge in the letter of
transmittal that it will deliver a prospectus meeting the requirements of the
Securities Act in connection with any resale of these exchange notes. This
prospectus may be used by those broker-dealers to resell exchange notes they
receive pursuant to the exchange offer. We have agreed that we will allow this
prospectus to be used by any broker-dealer in any resale of exchange notes
until , 2002 (210 days from the date the registration statement relating
to this prospectus was declared effective).
Except as described above, this prospectus may not be used for an offer to
resell, resale or other transfer of exchange notes.
To the extent original notes are tendered and accepted in the exchange
offer, the principal amount of original notes that will be outstanding will
decrease with a resulting decrease in the liquidity in the market for the
original notes. Original notes that are still outstanding following the
completion of the exchange offer will continue to be subject to transfer
restrictions.
Terms of the Exchange Offer
Upon the terms and subject to the conditions of the exchange offer described
in this prospectus and in the accompanying letter of transmittal, we will
accept for exchange all original notes validly tendered and not withdrawn
before 5:00 p.m., New York City time, on the expiration date. We will issue
$1,000 principal amount of exchange notes in exchange for each $1,000 principal
amount of original notes accepted in the exchange offer. You may tender some or
all of your original notes pursuant to the exchange offer. However, original
notes may be tendered only in denominations of $100,000 or in integral
multiples of $1,000 in excess thereof.
The exchange offer is not conditioned upon any minimum aggregate principal
amount of original notes being tendered for exchange. As of the date of this
prospectus, an aggregate of $1 billion principal amount of original notes was
outstanding. This prospectus is being sent to all registered holders of
original notes. There will be no fixed record date for determining registered
holders of original notes entitled to participate in the exchange offer.
We intend to conduct the exchange offer in accordance with the applicable
requirements of the Securities Act and the Securities Exchange Act and the
rules and regulations of the SEC. Holders of original notes do not have any
appraisal or dissenters' rights under law or under the indenture in connection
with the exchange offer. Original notes that are not tendered for exchange in
the exchange offer will remain outstanding and continue to accrue interest and
will be entitled to the rights and benefits their holders have under the
indenture.
We will be deemed to have accepted for exchange validly tendered original
notes when we have given oral or written notice of the acceptance to the
exchange agent. The exchange agent will act as agent for the tendering holders
of original notes for the purposes of receiving the exchange notes from us and
delivering the exchange notes to the tendering holders.
If we do not accept for exchange any tendered original notes because of an
invalid tender, the occurrence of certain other events described in this
prospectus or otherwise, such unaccepted original notes will be returned,
without expense, to the holder tendering them or the appropriate book-entry
will be made, in each case, as promptly as practicable after the expiration
date.
We are not making, nor is our board of directors making, any recommendation
to you as to whether to tender or refrain from tendering all or any portion of
your original notes in the exchange offer. No one has been authorized to make
any such recommendation. You must make your own decision whether to tender your
28
original notes in the exchange offer and, if you decide to do so, you must also
make your own decision as to the aggregate amount of original notes to tender
after reading this prospectus and the letter of transmittal and consulting with
your advisers, if any, based on your own financial position and requirements.
Expiration Date; Extensions; Amendments
The term "expiration date" means 5:00 p.m., New York City time, on ,
2001, unless we, in our sole discretion, extend the exchange offer, in which
case the term "expiration date" shall mean the latest date and time to which
the exchange offer is extended.
If we determine to extend the exchange offer, we will notify the exchange
agent of any extension by oral or written notice.
We reserve the right, in our sole discretion:
. to delay accepting for exchange any original notes; or
. to extend or terminate the exchange offer and to refuse to accept
original notes not previously accepted if any of the conditions set forth
below under "--Conditions to the Exchange Offer" have not been satisfied
by the expiration date.
Without limiting the manner in which we may choose to make public
announcements of any delay in acceptance, extension, termination or amendment
of the exchange offer, we will have no obligation to publish, advertise or
otherwise communicate any public announcement, other than by making a timely
release to a financial news service.
During any extension of the exchange offer, all original notes previously
tendered will remain subject to the exchange offer. We will return any original
notes that we do not accept for exchange for any reason without expense to the
tendering holder as promptly as practicable after the expiration or earlier
termination of the exchange offer.
Procedures for Tendering
In order to exchange your original notes, you must complete one of the
following procedures by 5:00 p.m., New York City time, on the expiration date:
. if your original notes are in book-entry form, the book-entry procedures
for tendering your original notes must be completed as described below
under "--Book-Entry Transfer;"
. if you hold physical notes that are registered in your name (i.e., not in
book-entry form), you must transmit a properly completed and duly
executed letter of transmittal, certificates for the original notes you
wish to exchange, and all other documents required by the letter of
transmittal, to Wilmington Trust Company, the exchange agent, at its
address listed below under the heading "--Exchange Agent;" or
. if you cannot tender your original notes by either of the above methods
by the expiration date, you must comply with the guaranteed delivery
procedures described below under "--Guaranteed Delivery Procedures."
A tender of original notes by a holder that is not withdrawn prior to the
expiration date 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.
The method of delivery of original notes through DTC and the method of
delivery of the Letter of Transmittal and all other required documents to the
exchange agent is at the holder's election and risk. Holders
29
should allow sufficient time to effect the DTC procedures necessary to validly
tender their original notes to the exchange agent before the expiration date.
Holders should not send letters of transmittal or other required documents to
us.
We will determine, in our sole discretion, all questions as to the validity,
form, eligibility (including time of receipt), acceptance of tendered original
notes and withdrawal of tendered original notes, and our determination will be
final and binding. We reserve the absolute right to reject any and all original
notes not properly tendered or any original notes the acceptance of which
would, in the opinion of us or our counsel, be unlawful. We also reserve the
absolute right to waive any defects or irregularities or conditions of the
exchange offer as to any particular original notes either before or after the
expiration date. Our interpretation of the terms and conditions of the exchange
offer as to any particular original notes either before or after the expiration
date, including the instructions in the letter of transmittal, will be final
and binding on all parties. Unless waived, any defects or irregularities in
connection with tenders of original notes for exchange must be cured within
such time as we shall determine. Although we intend to notify holders of any
defects or irregularities with respect to tenders of original notes for
exchange, neither we nor the exchange agent nor any other person shall be under
any duty to give such notification, nor shall any of them incur any liability
for failure to give such notification. Tenders of original notes will not be
deemed to have been made until all defects or irregularities have been cured or
waived. Any original notes received by the exchange agent that are not properly
tendered and as to which the defects or irregularities have not been cured or
waived will be returned by the exchange agent to the tendering holders or, in
the case of original notes delivered by book-entry transfer within DTC, will be
credited to the account maintained within DTC by the participant in DTC which
delivered such original notes, unless otherwise provided in the letter of
transmittal, as soon as practicable following the expiration date.
In addition, we reserve the right in our sole discretion (a) to purchase or
make offers for any original notes that remain outstanding after the expiration
date, (b) as set forth below under "-Conditions to the Exchange Offer," to
terminate the exchange offer and (c) to the extent permitted by applicable law,
purchase original notes in the open market, in privately negotiated
transactions or otherwise. The terms of any such purchases or offers could
differ from the terms of the exchange offer.
By signing, or otherwise becoming bound by, the letter of transmittal, each
tendering holder of original notes (other than certain specified holders) will
represent to us that:
. it is acquiring the exchange notes and it acquired the original notes
being exchanged in the ordinary course of its business;
. it is not a broker-dealer tendering original notes acquired directly from
us;
. it is not participating, does not intend to participate and has no
arrangements or understandings with any person to participate in the
distribution (within the meaning of the Securities Act) of the exchange
notes; and
. it is not our "affiliate," within the meaning of Rule 405 under the
Securities Act, or, if it is our affiliate, it will comply with the
registration and prospectus delivery requirements of the Securities Act
to the extent applicable.
If the tendering holder is a broker-dealer that will receive exchange notes for
its own account in exchange for original notes that were acquired as a result
of market-making activities or other trading activities, it may be deemed to be
an "underwriter" within the meaning of the Securities Act. Any such holder will
be required to acknowledge in the letter of transmittal that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with
any resale of these exchange notes. The letter of transmittal states that by so
acknowledging and by delivering a prospectus, the broker-dealer will not be
deemed to admit that it is an "underwriter" within the meaning of the
Securities Act.
30
Book-Entry Transfer
If your original notes are in book-entry form and are registered in the name
of a broker, dealer, commercial bank, trust company or other nominee, you must
contact the registered holder of your original notes and instruct it to
promptly tender your original notes for exchange on your behalf.
The exchange agent will establish an account with respect to the original
notes at DTC promptly after the date of this prospectus. Your book-entry notes
must be transferred into the exchange agent's account at DTC in compliance with
DTC's transfer procedures in order for your notes to be validly tendered for
exchange. Any financial institution that is a participant in DTC's systems may
cause DTC to transfer original notes to the exchange agent's account. The DTC
participant, on your behalf, must transmit its acceptance of the exchange offer
to DTC. DTC will verify this acceptance, execute a book-entry transfer of the
tendered original notes into the exchange agent's account and then send to the
exchange agent confirmation of this book-entry transfer. The confirmation of
this book-entry transfer will include an "agent's message" confirming that DTC
has received an express acknowledgement from the DTC participant that the DTC
participant has received and agrees to be bound by the letter of transmittal
and that we may enforce the letter of transmittal against this participant.
Original notes will be deemed to be validly tendered for exchange only if the
exchange agent receives the book-entry confirmation from DTC, including the
agent's message, prior to the expiration date.
All references in this prospectus to deposit or delivery of original notes
shall be deemed to also refer to DTC's book-entry delivery method.
Guaranteed Delivery Procedures
Holders who wish to tender their original notes and (1) whose original notes
are not immediately available or (2) who cannot deliver the letter of
transmittal or any other required documents to the exchange agent prior to the
expiration date or (3) who cannot complete the procedures for book-entry
transfer on a timely basis may effect a tender if:
. the tender is made through an eligible institution;
. before the expiration date, the exchange agent receives from the eligible
institution a properly completed and duly executed notice of guaranteed
delivery, by facsimile transmission, mail or hand delivery, listing the
principal amount of original notes tendered, stating that the tender is
being made thereby and guaranteeing that, within three New York Stock
Exchange, Inc. trading days after the expiration date, a duly executed
letter of transmittal together with a confirmation of book-entry transfer
of such original notes into the exchange agent's account at DTC, and any
other documents required by the letter of transmittal and the
instructions thereto, will be deposited by such eligible institution with
the exchange agent; and
. within three New York Stock Exchange trading days after the expiration
date, the exchange agent receives a confirmation of book-entry transfer
of all tendered original notes into the exchange agent's account at DTC
in the case of book-entry notes, or a properly completed and executed
letter of transmittal and the physical notes, in the case of notes in
certificated form, and all other documents required by the letter of
transmittal.
Upon request to the exchange agent, a notice of guaranteed delivery will be
sent to holders who wish to tender their original notes according to the
guaranteed delivery procedures described above.
Withdrawal of Tenders
Except as otherwise provided in this prospectus, tenders of original notes
may be withdrawn at any time prior to 5:00 p.m., New York City time, on the
expiration date.
31
For a withdrawal to be effective, the exchange agent must receive a written
or facsimile transmission notice of withdrawal at one of its addresses set
forth below under "--Exchange Agent." Any notice of withdrawal must:
. specify the name of the person who tendered the original notes to be
withdrawn;
. identify the original notes to be withdrawn, including the principal
amount of such original notes;
. state that the holder is withdrawing its election to exchange the
original notes to be withdrawn;
. be signed by the holder in the same manner as the original signature on
the letter of transmittal by which the original notes were tendered and
include any required signature guarantees; and
. specify the name and number of the account at DTC to be credited with
the withdrawn original notes and otherwise comply with the procedures of
DTC.
We will determine, in our sole discretion, all questions as to the validity,
form and eligibility (including time of receipt) of any notice of withdrawal,
and our determination shall be final and binding on all parties. Any original
notes so withdrawn will be deemed not to have been validly tendered for
exchange for purposes of the exchange offer, and no exchange notes will be
issued with respect thereto unless the original notes so withdrawn are validly
re-tendered. Properly withdrawn original notes may be re-tendered by following
one of the procedures described above under "--Procedures for Tendering" at any
time prior to the expiration date.
Any original notes that are tendered for exchange through the facilities of
DTC but that are not exchanged for any reason will be credited to an account
maintained with DTC for the original notes as soon as practicable after
withdrawal, rejection of tender or termination of the exchange offer.
Conditions to the Exchange Offer
Despite any other term of the exchange offer, we will not be required to
accept for exchange, or to issue exchange notes in exchange for, any original
notes, and we may terminate the exchange offer as provided in this prospectus
prior to the expiration date, if:
. we are not permitted to effect the exchange offer according to the
registration rights agreement because of any change in law, regulation
or any applicable interpretation of the SEC staff; or
. a pending or threatened action or proceeding would impair our ability to
proceed with the exchange offer.
These conditions are for our sole benefit and may be asserted by us
regardless of the circumstances giving rise to any of these conditions or may
be waived by us, in whole or in part, at any time and from time to time in our
reasonable discretion. Our failure at any time to exercise any of the foregoing
rights shall not be deemed a waiver of the right and each right shall be deemed
an ongoing right which may be asserted at any time and from time to time.
If we determine in our reasonable judgment that any of the conditions are
not satisfied, we may:
. refuse to accept and return to the tendering holder any original notes
or credit any tendered original notes to the account maintained within
DTC by the participant in DTC which delivered the original notes, or
. extend the exchange offer and retain all original notes tendered before
the expiration date, subject to the rights of holders to withdraw the
tenders of original notes (see "--Withdrawal of Tenders" above), or
. waive the unsatisfied conditions with respect to the exchange offer
prior to the expiration date and accept all properly tendered original
notes that have not been withdrawn or otherwise amend the terms of the
exchange offer in any respect as provided under "--Expiration Date;
Extensions; Amendments."
32
In addition, we will not accept for exchange any original notes tendered,
and we will not issue exchange notes in exchange for any of the original notes,
if at that time any stop order is threatened or in effect with respect to the
registration statement of which this prospectus constitutes a part or the
qualification of the indenture under the Trust Indenture Act of 1939.
Exchange Agent
Wilmington Trust Company has been appointed as the exchange agent for the
exchange offer. All signed letters of transmittal and other documents required
for a valid tender of your original notes should be directed to the exchange
agent at one of the addresses set forth below. Questions and requests for
assistance, requests for additional copies of this prospectus or of the letter
of transmittal and requests for notices of guaranteed delivery should be
directed to the exchange agent addressed as follows:
BY REGISTERED, CERTIFIED MAIL OR BY FACSIMILE:
BY HAND OR OVERNIGHT DELIVERY:
Wilmington Trust Company, as Exchange Agent Fax number: (302) 651-8882
Rodney Square North Attention: Corporate Trust Reorg Svcs
1100 North Market Street PG&E National Energy Group, Inc. Exchange Offer
Wilmington, Delaware 19890-0001 Confirm by telephone: (302) 651-1000
Attention: Corporate Trust Reorg Svcs
PG&E National Energy Group, Inc. Exchange
Offer
For information call: (302) 651-1000
Delivery to other than the above address or facsimile number will not
constitute a valid delivery.
Fees and Expenses
We will bear the expenses of soliciting tenders for the exchange offer.
These expenses include fees and expenses of the exchange agent and the trustee,
the registration fee, accounting and legal fees, printing costs, and related
fees and expenses. We will principally solicit tenders for the exchange offer
by mail or overnight courier, although our officers and regular employees may
additionally solicit in person or by telephone or facsimile.
We have not retained any dealer-manager in connection with the exchange
offer and will not pay any brokers, dealers or others soliciting acceptance of
the exchange offer. We, however, will pay the exchange agent reasonable and
customary fees for its services and its reasonable out-of-pocket expenses. We
may also pay brokerage houses and other custodians, nominees and fiduciaries
their reasonable out-of-pocket expenses for sending copies of this prospectus,
letters of transmittal and related documents to holders of the original notes,
and in tendering original notes for their customers.
Transfer Taxes
Holders who tender their original notes for exchange will not be obligated
to pay any transfer taxes in connection with the exchange offer.
Accounting Treatment
We will recognize no gain or loss, for accounting purposes, as a result of
the exchange offer. The expenses of the exchange offer and the unamortized
expenses relating to the issuance of the original notes will be amortized over
the term of the exchange notes.
33
Consequences of Failure to Exchange
Holders of original notes who do not exchange their original notes for
exchange notes pursuant to the exchange offer will not be able to offer, sell
or otherwise transfer the original notes except in compliance with the
registration requirements of the Securities Act and other applicable securities
laws, pursuant to an exemption from the securities laws or in a transaction not
subject to the securities laws. Original notes not exchanged pursuant to the
exchange offer will otherwise remain outstanding in accordance with their
respective terms and will continue to bear a legend reflecting these
restrictions on transfer. Holders of original notes do not have any appraisal
or dissenters' rights under the Delaware General Corporation Law in connection
with the exchange offer.
Upon completion of the exchange offer, holders of original notes will not be
entitled to any rights to have the resale of original notes registered under
the Securities Act except to the limited extent that certain qualified
institutional buyers, if any, are otherwise entitled under the registration
rights agreement to have their original notes registered under a shelf
registration. Except for this limited circumstance, we do not intend to
register under the Securities Act the resale of any original notes that remain
outstanding after completion of the exchange offer.
34
CAPITALIZATION
The following table sets forth our capitalization as of June 30, 2001. Our
capitalization reflects the receipt and application of the net proceeds from
the sale of the original notes.
You should read the information in this table together with our consolidated
financial statements and the notes to those financial statements and with
"Selected Consolidated Financial Data" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included elsewhere
in this prospectus.
As of
June 30, 2001
-------------
(in millions)
(unaudited)
Cash and cash equivalents......................................... $ 801
======
Current portion of long-term debt................................. 10
Short-term borrowings(1).......................................... 445
Short-term debt--parent........................................... 309
------
Total short-term debt........................................... 764
------
Long-term debt.................................................... 2,104
Long-term advances from Parent.................................... 118
------
Total long-term debt............................................ 2,222
------
Preferred stock of subsidiary..................................... 58
Minority equity interests......................................... 19
Common stockholder's equity....................................... 2,363
------
Total capitalization............................................ $5,426
======
- --------
(1) We have the option to defer the repayment of the short-term borrowings for
two years.
35
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data as of December 31, 1999
and 2000, and for the years ended December 31, 1998, 1999 and 2000, have been
derived from our audited consolidated financial statements and the related
notes. The consolidated financial data as of December 31, 1996, 1997 and 1998,
and as of June 30, 2000 and 2001, and for the years ended December 31, 1996 and
1997, and the six months ended June 30, 2000 and 2001 have been derived from
our unaudited financial statements. The information set forth below should be
read together with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and our historical consolidated financial statements
and the notes to those statements included elsewhere in this prospectus.
PG&E National Energy Group, Inc. was incorporated on December 18, 1998.
Shortly thereafter, PG&E Corporation contributed various subsidiaries to us.
Our consolidated financial statements for all periods presented in the tables
below have been prepared on a basis that includes the historical financial
position and results of operations of the subsidiaries that were wholly owned
or majority-owned and controlled by us as of December 31, 2000. For those
subsidiaries that were acquired or disposed of during the periods presented by
us, or by PG&E Corporation prior to or after our formation, the results of
operations are included from the date of acquisition. For those subsidiaries
disposed of during the periods presented, the results of operations are
included through the date disposed.
The following selected consolidated financial data should also be read in
light of the following:
. In September 1997, we became the sole owner of PG&E Generating Company,
a joint venture which owned, developed and managed independent power
projects. This joint venture was formerly known as U.S. Generating
Company or US Gen. In connection with this transaction, we acquired
various ownership interests that gave us full or part ownership of
twelve domestic generating facilities. In April 1997, we sold our
interest in International Generating Company, Ltd., an international
developer of generating facilities, resulting in an after-tax gain of
$120 million. Our 1997 results also reflect the write-off of our $87
million investment in two generating facilities that we had developed
and constructed in Florida to burn agricultural waste, but only operated
for a short period of time because of a dispute with the power
purchaser.
. In January 1997, we acquired Teco Pipeline Company for $378 million and,
in July 1997, Valero Energy Corporation's natural gas business located
in Texas for total consideration, including assumption of its debt, of
approximately $1.5 billion. These two operations, which we called GTT,
made up the bulk of our natural gas operations in Texas. On January 27,
2000, we signed a definitive agreement with El Paso Field Services
Company to sell GTT. We completed this sale on December 22, 2000. In
1999, we recognized a $1,275 million charge against pre-tax earnings
($890 million after tax) to reflect GTT's assets at their net realizable
value. In 2000, prior to the closing of the sale, we recognized income
of approximately $33 million.
. In September 1998, we acquired for approximately $1.8 billion a
portfolio of hydroelectric, coal, oil, and natural gas generating
facilities with an aggregate generating capacity of 4,000 MW located in
New England from NEP, a subsidiary of New England Electric System. We
also assumed the purchase obligations under 23 multi-year power purchase
agreements representing an additional 800 MW of production capacity. In
return for our assumption of these power purchase agreements, we are
receiving the benefit of monthly payments from NEP through January 2008.
As of December 31, 2000, NEP owed gross payments of $790 million under
this arrangement. In connection with the acquisition, we further agreed
to provide electricity to certain retail providers in New England at
predetermined rates.
. In July 1998, we sold our Australian energy holdings for $126 million.
We recognized a $23 million loss related to the sale.
. One of the businesses that PG&E Corporation contributed to us in 1998
provided retail power and gas commodity products and energy management
services to end-users. Due to a revised assessment of the
36
market potential for retail energy services, we decided in December 1999
to sell this business and reflected it in the financial statements as a
discontinued operation. Our 1999 results include losses aggregating $105
million after-tax, including the write-down of this business to its
estimated net realizable value and establishment of a reserve for
anticipated losses. We completed the sale of this business in two
transactions in 2000, recording an additional after-tax loss of $40
million in 2000.
. Some of the costs reflected in the consolidated financial data are for
functions and services provided by PG&E Corporation that are directly
attributable to us, which are charged to us based on usage and other
allocation factors, as well as generate corporate expenses allocated by
PG&E Corporation based on assumptions that management believes are
reasonable under the circumstances.
Six Months Ended
Year Ended December 31, June 30,
------------------------------------------------- -----------------------
1996 1997 1998 1999 2000 2000 2001
----------- ----------- ------- ------- ------- ----------- -----------
(unaudited) (unaudited) (unaudited) (unaudited)
Income Statement Data
(in millions):
Operating revenues...... $426 $6,101 $10,650 $12,020 $16,995 $6,693 $6,964
Impairments and write-
offs................... 60 87 -- 1,275 -- -- --
Other operating
expenses............... 306 6,081 10,488 11,851 16,604 6,501 6,754
---- ------ ------- ------- ------- ------ ------
Total operating
expenses........... 366 6,168 10,488 13,126 16,604 6,501 6,754
---- ------ ------- ------- ------- ------ ------
Operating income
(loss)................. 60 (67) 162 (1,106) 391 192 210
Other income (expense):
Interest income....... 18 29 45 75 80 34 49
Interest expense...... (46) (81) (156) (162) (155) (78) (58)
Other, net............ 6 119 (7) 52 6 (9) 6
---- ------ ------- ------- ------- ------ ------
Income (loss) from
continuing operations
before income taxes.... 38 -- 44 (1,141) 322 139 207
Income tax expense
(benefit).............. 30 (32) 41 (351) 130 55 82
---- ------ ------- ------- ------- ------ ------
Income (loss) from
continuing operations.. 8 32 3 (790) 192 84 125
Discontinued
operations, net of
income taxes......... -- (28) (57) (105) (40) -- --
---- ------ ------- ------- ------- ------ ------
Net income (loss) before
cumulative effect of a
change in accounting
principle.............. 8 4 (54) (895) 152 84 125
Cumulative effect of a
change in accounting
principle, net of
income taxes........... -- -- -- 12 -- -- --
---- ------ ------- ------- ------- ------ ------
Net income (loss)....... $ 8 $ 4 $ (54) $ (883) $ 152 $ 84 $ 125
==== ====== ======= ======= ======= ====== ======
Other Data:
Ratio of earnings to
fixed charges(1)....... 1.3 1.1 1.0 Note 2 2.2 2.1 2.7
- --------
(1) For purposes of calculating the ratio of earnings to fixed charges,
earnings consist of earnings from continuing operations before income taxes
and fixed charges (exclusive of interest capitalized). Fixed charges
consist of interest on all indebtedness (including amounts capitalized),
amortization of debt issuance costs and the portion of lease rental expense
that represents a reasonable approximation of the interest factor.
(2) The ratio of earnings to fixed charges was negative for the year ended
December 31, 1999. The amount of the coverage deficiency was $1,140
million.
37
As of December 31, As of
-------------------------------------------------- June 30,
1996 1997 1998 1999 2000 2001
----------- ----------- ----------- ------ ------- -----------
(unaudited) (unaudited) (unaudited) (unaudited)
Balance Sheet Data (in
millions):
Cash and cash
equivalents............ $ 149 $ 301 $ 168 $ 228 $ 738 $ 801
Price risk management
assets, current........ 17 500 1,416 389 2,039 2,656
Other current assets.... 585 1,426 1,161 1,508 3,343 1,808
------ ------ ------- ------ ------- -------
Total current assets.. 751 2,227 2,745 2,125 6,120 5,265
------ ------ ------- ------ ------- -------
Property, plant and
equipment, net......... 1,220 3,215 4,962 4,054 3,640 3,864
Investments in
affiliates............. 701 587 572 530 417 420
Price risk management
assets, noncurrent..... -- 58 334 319 2,026 1,045
Other noncurrent
assets................. 189 791 1,534 1,038 903 1,363
------ ------ ------- ------ ------- -------
Total assets.......... $2,861 $6,878 $10,147 $8,066 $13,106 $11,957
====== ====== ======= ====== ======= =======
Short-term borrowings... $ -- $ 100 $ 293 $ 524 $ 519 $ 445
Price risk management
liabilities, current... -- 476 1,412 323 1,999 2,545
Other current
liabilities............ 505 1,456 1,173 1,549 3,315 1,780
------ ------ ------- ------ ------- -------
Total current
liabilities.......... 505 2,032 2,878 2,396 5,833 4,770
------ ------ ------- ------ ------- -------
Long-term debt.......... 715 1,563 1,955 1,805 1,390 2,104
Price risk management
liabilities,
noncurrent............. -- 46 281 207 1,867 1,028
Other long-term
liabilities............ 409 848 2,233 1,776 1,637 1,615
------ ------ ------- ------ ------- -------
Total liabilities..... 1,629 4,489 7,347 6,184 10,727 9,517
------ ------ ------- ------ ------- -------
Preferred stock of
subsidiary and minority
interests.............. 92 96 81 78 75 77
Stockholder's equity.... 1,140 2,293 2,719 1,804 2,304 2,363
------ ------ ------- ------ ------- -------
Total liabilities and
stockholder's
equity............... $2,861 $6,878 $10,147 $8,066 $13,106 $11,957
====== ====== ======= ====== ======= =======
38
Six
Months
Ended
Year Ended December 31, June 30,
------------------------ ---------
1996 1997 1998 1999 2000 2000 2001
---- ---- ---- ---- ---- ---- ----
Other Data (in millions, unaudited):
Adjusted EBITDA(1).......................... $196 $267 $322 $396 $526 $237 $304
- --------
(1) Adjusted EBITDA is defined as income from continuing operations before
provision for income taxes, interest expense, depreciation and
amortization, including amortization of out-of-market contractual
obligations. Adjusted EBITDA excludes non-cash impairment charges and
write-offs. Adjusted EBITDA also includes all cash offset payments from NEP
related to our assumption of the purchase obligations under power purchase
agreements in our 1998 acquisition of our New England generating
facilities. Adjusted EBITDA is not intended to represent cash flows from
operations and should not be considered as an alternative to net income as
an indicator of our operating performance or as an alternative to cash
flows as a measure of liquidity. Refer to the Statement of Cash Flows for
the cash flows determined in accordance with generally accepted accounting
principles in the United States. We believe that Adjusted EBITDA is a
standard measure commonly reported and widely used by analysts, investors
and other interested parties. However, Adjusted EBITDA as presented in this
prospectus may not be comparable to similarly titled measures reported by
other companies. Adjusted EBITDA is composed of the following items (in
millions, unaudited):
Six
Months
Ended
Year Ended December 31, June 30,
------------------------------ ----------
1996 1997 1998 1999 2000 2000 2001
---- ---- ---- ------ ----- ---- ----
Income (loss) from continuing
operations........................ $ 8 $ 32 $ 3 $ (790) $ 192 $ 84 $125
Add:
Income tax expense (benefit)..... 30 (32) 41 (351) 130 55 82
Depreciation and amortization
expense......................... 52 99 167 214 143 70 75
Interest expense................. 46 81 156 162 155 78 58
Impairments and write-offs....... 60 87 -- 1,275 -- -- --
Amortization of out-of-market
contractual obligations......... -- -- (65) (181) (163) (84) (73)
Cash offset payments related to
NEP power supply agreements..... -- -- 20 67 69 34 37
---- ---- ---- ------ ----- ---- ----
Adjusted EBITDA as defined..... $196 $267 $322 $ 396 $ 526 $237 $304
==== ==== ==== ====== ===== ==== ====
39
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with "Special Note
Regarding Forward-Looking Statements," "Risk Factors," "Selected Consolidated
Financial Data" and our consolidated financial statements and related notes
included elsewhere in this prospectus.
Overview
We are an integrated energy company with a strategic focus on power
generation, greenfield development, natural gas transmission and wholesale
energy marketing and trading in North America. We have integrated our
generation, development and energy marketing and trading activities to increase
the returns from our operations, identify and capitalize on opportunities to
increase our generating and pipeline capacity, create energy products in
response to dynamic markets and manage risks. We intend to expand our
generating and natural gas pipeline capacity and enhance our growth and
financial returns through our energy marketing and trading capabilities.
We account for our business in two reportable segments, integrated energy
and marketing, or energy, and interstate pipeline operations, or pipeline.
Energy is comprised of PG&E Generating Company, LLC and PG&E Energy Trading
Holdings Corporation and their subsidiaries. Pipeline includes GTN and GTT.
GTT, when acquired in 1997, included pipeline operations, natural gas
processing operations and energy trading activities. GTT's energy trading
activities were reorganized and transferred in two stages to our energy segment
in 1998 and 1999. Our sale of GTT, which was completed in December 2000,
included the energy trading activities originally acquired in 1997. The
activities in our energy segment that were disposed of as part of the GTT sale
provided approximately $123 million, $605 million and $1.0 billion in operating
revenues in 1998, 1999 and 2000, respectively, and $504 million in the six
months ended June 30, 2000. Income from continuing operations contributed by
these activities was $13 million in 2000, negligible in 1999 and 1998 and $9
million in the six months ended June 30, 2000.
The following table sets forth the operating revenues and income (loss) from
continuing operations attributable to each of our operating segments (in
millions):
Six Months
Year Ended December 31, Ended June 30,
------------------------- ----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
(unaudited)
Operating revenues
Integrated energy and
marketing...................... $ 8,466 $10,612 $15,907 $ 6,130 $ 6,831
Interstate pipeline operations:
GTN........................... 237 243 239 113 129
GTT........................... 1,941 1,148 873 449 --
Eliminations and other.......... 6 17 (24) 1 4
------- ------- ------- ------- -------
Total operating revenues.... $10,650 $12,020 $16,995 $ 6,693 $ 6,964
======= ======= ======= ======= =======
Income (loss) from continuing
operations
Integrated energy and
marketing...................... $ 35 $ 22 $ 104 $ 56 $ 88
Interstate pipeline operations:
GTN........................... 60 61 58 27 38
GTT........................... (71) (908) 20 -- --
Eliminations and other.......... (21) 35 10 1 (1)
------- ------- ------- ------- -------
Total income (loss) from
continuing operations...... $ 3 $ (790) $ 192 $ 84 $ 125
======= ======= ======= ======= =======
Net cash provided by (used in)
operating activities............. $ 64 $ 74 $ 163 $ (68) $ 19
Net cash provided by (used in)
investing activities............. $(1,285) $ (63) $ (144) $ 12 $ (523)
Net cash provided by (used in)
financing activities............. $ 1,088 $ 49 $ 491 $ 46 $ 567
40
Sources of Revenue
We derive our revenue primarily through the marketing and trading of
electricity and related products, fuel (including natural gas, coal and fuel
oil), fuel services such as transport and storage, emission credits and other
related products. We recognize revenue on delivery contracts when they settle.
We also recognize as revenue the unrealized gain or loss on trading contracts
that have not settled by valuing these contracts at their fair values at the
end of each period. In addition, we manage the risk of our portfolio regionally
by entering into hedging transactions to purchase and sell electricity and
fuel. If certain criteria are met, gain or loss from our hedging activities is
deferred and not recognized until the underlying item is purchased or sold.
This gain or loss may fluctuate from period to period in response to changes in
the energy markets and the duration of our contracts.
During 2000, we sold approximately 80% of the electric output of our
generating facilities under long-term power sales agreements at fixed or
formula-derived prices (including the wholesale standard offer agreements) and
the balance at market prices under contracts of varying duration through our
energy trading operations. We recognize revenues under these agreements upon
output, product delivery or satisfaction of specified targets. The fixed and
formula-derived price agreements offer revenue stability.
We also derive revenue from the transportation of gas through our gas
transmission operations at prices based on contractual arrangements under rate
schedules approved by FERC. During 2000, 96% of GTN's capacity was committed to
long-term firm transportation services agreements with a weighted average
remaining term of approximately 13 years. We also earn revenues from short-term
firm and interruptible transportation services from remaining available
capacity. Gas transportation revenues are recognized as the services are
provided.
Operating Expenses
Our major costs are electricity and fuel. We recognize expense on purchase
contracts when they settle. Operating expenses also include our net gains or
losses on hedges of purchase contracts. We have entered into long-term
agreements to buy the fuel needed for 12 of our generating facilities at fixed
rates or variable market prices adjusted periodically. These contracts provide
us with a certain level of stability in our fuel expense. We recognize expenses
under these contracts when the fuel is delivered.
Our operations, maintenance and management expenses consist of the costs
related to the operation and periodic upkeep of our generation and gas
transmission assets, as well as the costs related to our marketing and trading
operations. In addition, operations, maintenance and management expense
includes the cost of major overhauls and turbine repairs on an as-incurred
basis, which may cause this expense to fluctuate from period to period.
Our administrative and general expenses include the cost of corporate
support and shared administrative services. These expenses also include
administrative and general costs allocated from PG&E Corporation. These charges
from PG&E Corporation are based upon direct assignment of costs and allocations
of costs using allocation methods that we and PG&E Corporation believe are
reasonable reflections of the utilization of services provided to or for the
benefits received by us. These expenses also include the costs of our energy
marketing and trading operations, which include the salaries and related
benefits of our energy marketers and traders, as well as maintenance and upkeep
of the trading systems.
Our other recurring operating expenses primarily represent depreciation and
amortization.
We are included in the consolidated tax return of PG&E Corporation. Through
our tax-sharing arrangement with PG&E Corporation, we have recognized tax
expense or benefit based upon our share of consolidated income or loss through
an allocation of income taxes from PG&E Corporation which allowed us to utilize
the tax benefits we generated so long as they could be used on a consolidated
basis. Beginning with the 2001 calendar year, we expect to pay to PG&E
Corporation the amount of income taxes that we would be
41
liable for if we filed our own consolidated combined or unitary return separate
from PG&E Corporation, subject to certain consolidated adjustments. These
changes would not have affected our net income or total assets in 1998, 1999 or
2000, or in the six months ended June 30, 2000 and 2001.
Results of Operations
Six Months Ended June 30, 2001 as Compared to Six Months Ended June 30, 2000
Operating Revenues. Our operating revenues were $7.0 billion in the six
months ended June 30, 2001, an increase of $0.3 billion, or 4%, from the six
months ended June 30, 2000.
Operating revenues for our energy segment were $6.8 billion in the six
months ended June 30, 2001, an increase of $0.7 billion, or 11%, from the six
months ended June 30, 2000. Operating revenues over the six-month period
increased as a result of increases in the prices of power and gas, and a focus
of our trading efforts on asset management and higher-margin trades. These
increases were partially offset by decreases in commodity sales and declines in
the market value of long-term gas transportation contracts during the second
quarter.
Operating revenues for our pipeline segment were $129 million in the six
months ended June 30, 2001, a decrease of $433 million, or 77%, from the six
months ended June 30, 2000. Short-term firm revenues earned by our GTN pipeline
increased, resulting from high capacity load factors and improved pricing
fundamentals in gas transport to western gas markets. These GTN increases were
offset by the completion in late 2000 of the sale of GTT, which had revenues of
$449 million for the six months ended June 30, 2000.
Operating Expenses. Our operating expenses were $6.8 billion in the six
months ended June 30, 2001, an increase of $0.3 billion, or 5%, from the six
months ended June 30, 2000. The increase primarily resulted from higher costs
of commodities and fuel in the energy segment, partially offset by overall
reduced operational costs at our facilities, and the reduction of pipeline
segment costs as a result of the sale of GTT in late 2000. Transactions in
California had a slight negative impact on other operating expenses in the
energy segment for the six months ended June 30, 2001.
Other Income (Expense). Interest expense was $58 million in the six months
ended June 30, 2001, a decrease of $20 million, or 26%, from the six months
ended June 30, 2000. The decrease was primarily due to the reduction of debt as
a result of utilizing a portion of the proceeds from the May 2001 issuance of
the $1 billion original notes to pay down revolving credit facilities and the
sale of GTT in late 2000. Interest income was $49 million in the six months
ended June 30, 2001, an increase of $15 million, or 44%, from the six months
ended June 30, 2000. The increase resulted from interest earned on the
remaining proceeds from the $1 billion original notes issuance and cash
proceeds received from the sale of GTT.
Year Ended December 31, 2000 as Compared to Year Ended December 31, 1999
Operating Revenues. Our operating revenues were $17.0 billion in 2000, an
increase of $5.0 billion, or 41%, from 1999.
Operating revenues for our energy segment were $15.9 billion in 2000, an
increase of $5.3 billion, or 50%, from 1999. This increase was primarily the
result of the increased volume of trades of electricity and related products
and generally higher prices for both electricity and natural gas. In addition,
two of our New England generating facilities were not in service for a portion
of summer 1999 because of two fires. There were no significant unanticipated
outages during 2000.
Operating revenues for our pipeline segment were $1.1 billion in 2000, a
decrease of $279 million, or 20%, from 1999. GTN's operating revenues were $239
million in 2000, a decrease of $4 million, or 2%, from 1999. This decrease
reflects the recognition of $19 million in revenues in 1999 from the
renegotiation of several transportation service contracts in connection with
the resolution of commercial issues with certain
42
shippers, partially offset by higher short-term firm and interruptible service
revenues in 2000. GTT's revenues were $873 million in 2000, a decrease of $275
million, or 24%, from 1999, resulting from the decrease in natural gas sales
resulting from the transfer of certain gas marketing activities conducted by
GTT to our energy segment operations in the middle of 1999 and resulting from
eleven months of revenues in 2000 versus a full year of revenues in 1999. This
decrease was partially offset by the significant increase in the price of
natural gas liquids.
Operating Expenses. Our operating expenses were $16.6 billion in 2000, an
increase of $3.5 billion, or 27%, from 1999.
The cost of commodity sales and fuel was $15.7 billion in 2000, an increase
of $4.7 billion, or 43%, from 1999. The cost of electricity and related product
purchases increased between the periods reflecting the increased volume of
trades of electricity and related products and the generally higher price of
electricity in 2000. This increase was partially offset by lower fuel costs at
our generating facilities resulting from reduced fuel consumption.
Operations, maintenance and management expense was $716 million in 2000, an
increase of $115 million, or 19%, from 1999, primarily due to additional
maintenance activities at our coal-fired plants.
Depreciation and amortization expense was $143 million in 2000, a decrease
of $71 million, or 33%, from 1999. This decrease was primarily due to the
cessation of depreciation expense recognition in 2000 on the GTT pipeline
assets held for sale under the sales agreement signed in January 2000.
Administrative and general expenses were $68 million in 2000, an increase of
$19 million, or 39%, from 1999, primarily reflecting $22 million in expenses
incurred to relocate our natural gas marketing and trading operations from
Houston to Bethesda.
In January 2000, we signed a definitive agreement to sell the stock of GTT.
Based on the terms of the sales agreement, we recognized an impairment charge
of $1,275 million in 1999 to reflect GTT's assets at their fair value. We
recorded no impairments or write-offs in 2000.
Other operating expenses were $10 million in 2000, an increase of $5 million
from 1999.
Other Income (Expense). Interest expense was $155 million in 2000, a
decrease of $7 million, or 4%, from 1999. This decrease resulted from the
reduction of GTT and GTN debt and from eleven months of interest on the GTT
debt in 2000 versus twelve months of interest in 1999. Interest income was $80
million in 2000, an increase of $5 million, or 7%, from 1999. Other income was
$6 million in 2000, a decrease of $46 million, or 88%, from 1999. This decrease
was primarily caused by the one-time reversal in 1999 of a $55 million legal
contingency accrual as the result of the favorable resolution of certain legal
proceedings.
Income Taxes. Income tax expense from continuing operations was $130 million
in 2000, an increase of $481 million from 1999, reflecting the increase in our
pre-tax income. Our effective income tax rate was 40% in 2000. Tax amounts
recorded in 1999 in connection with the GTT sale, including a stock sale
valuation allowance, contributed to a net income tax benefit of $351 million in
1999.
Year Ended December 31, 1999 as Compared to Year Ended December 31, 1998
Operating Revenues. Our operating revenues were $12.0 billion in 1999, an
increase of $1.4 billion, or 13%, from 1998.
Operating revenues for our energy segment were $10.6 billion in 1999, an
increase of $2.1 billion, or 25%, from 1998. This increase was primarily the
result of an increased volume of trades and the inclusion in 1999 of a full
year's operations for the New England generating facilities that we acquired in
September 1998, as compared to approximately three months of operations for
these facilities in 1998.
43
Operating revenues for our pipeline segment were $1.4 billion in 1999, a
decrease of $787 million, or 36%, from 1998. GTN's operating revenues were $243
million in 1999, an increase of $6 million, or 3%, from 1998. This increase was
attributable to revenue recognized in 1999 upon renegotiation of several
contracts as described previously, partially offset by lower short-term firm
and interruptible revenues. GTT's operating revenues were $1.1 billion in 1999,
a decrease of $793 million, or 41%, from 1998, reflecting the mid-1999 transfer
of certain gas marketing activities conducted by GTT to our energy segment
operations, partially offset by higher natural gas liquids prices.
Operating Expenses. Our operating expenses were $13.1 billion in 1999, an
increase of $2.6 billion, or 25%, from 1998. This increase includes $1,275
million in impairments and write-offs to reflect GTT's assets at their net
realizable value in contemplation of the sale of GTT. We recorded no write-offs
or impairments in 1998. Excluding this non-recurring charge, operating expenses
increased $1.4 billion, or 13%, in 1999 from 1998.
The cost of commodity sales and fuel was $11.0 billion in 1999, an increase
of $1.1 billion, or 11%, from 1998. This increase reflects additional volumes
of trades in both electricity and natural gas and their related products in our
energy marketing and trading operation, partially offset by the reduction in
volumes sold by GTT.
Operations, maintenance and management expense was $601 million in 1999, an
increase of $206 million, or 52%, from 1998. This increase was principally due
to the inclusion in 1999 of a full year of operations and maintenance expenses
associated with the New England generating facilities that we acquired in
September 1998, as compared to approximately three months of operations of
these facilities in 1998.
Administrative and general expenses were $49 million in 1999, an increase of
$4 million, or 9%, from 1998, primarily reflecting expansion of our energy
marketing and trading staff and infrastructure.
Depreciation and amortization expense was $214 million in 1999, an increase
of $47 million, or 28%, from 1998, primarily due to the inclusion of a full
year's depreciation associated with the New England generating facilities.
Other operating expenses were $5 million in 1999, a decrease of $2 million
from 1998.
Other Income (Expense). Interest expense was $162 million in 1999, an
increase of $6 million, or 4%, from 1998. The effect in 1999 of the full year
of borrowing costs associated with acquisition of the New England generating
facilities was partially offset by decreases in GTT interest expense resulting
from reduction of outstanding debt. Interest income was $75 million in 1999, an
increase of $30 million from 1998. This increase was principally the result of
a full year of interest income recognition related to the offset payments from
NEP related to our acquisition of the New England generating facilities, which
have been recorded as a long-term receivable in our financial statements. In
1999, we reversed a legal contingency accrual of $55 million as previously
discussed. In 1998, we recognized a $23 million loss on the sale of our
Australian holdings.
Income Taxes. We recorded a $351 million income tax benefit from continuing
operations in 1999 compared to the provision for income taxes from continuing
operations of $41 million in 1998. The 1999 tax benefit was generated from the
loss associated with the disposition of GTT and other net operating losses.
Seasonality
Our operations vary depending upon the season, although the impact of each
season can vary depending upon geographic location. In many areas, the demand
for electricity peaks during the hot summer months, with energy and capacity
prices also generally being the highest at that time. In some areas, demand for
electricity also increases during the coldest winter months. Demand for gas
supply and transportation also increases
44
during the cold months with the use of natural gas for heating purposes. These
seasonal changes in demand often are accompanied by changes in prices and
generating margins, which tend to increase in periods of high demand. In
addition, output from our hydroelectric plants fluctuates depending upon the
availability of water flows, particularly in the Connecticut River in New
England. Generally more water is available during rainy months or as a result
of snowmelt in the late winter and spring. These periods of increased water
flow tend to result in increased energy production.
We expect to earn a relatively higher proportion of our annual income during
the months with high electricity demand than we earn during the other periods
of the year. This fluctuation in income currently is somewhat mitigated by our
long-term power sales agreements and other agreements that establish set
prices, in some cases, with fuel cost adjustment provisions. We also attempt to
mitigate our exposure to seasonal influences by hedging some or all of our
power and fuel sales and purchases. Maintenance scheduling, geographic
diversity, business diversity and hedging positions also tend to reduce
seasonal fluctuations in income. Our future overall operating results may
exhibit different seasonal aspects than we currently experience, depending upon
the location and characteristics of any additional facilities that we control
or contracts into which we enter.
Liquidity and Capital Resources
Capital expenditures in our generation operations and natural gas
transmission business, debt service requirements and working capital needs
associated with our energy trading and marketing operations have been the
primary demands on our cash resources. In addition, we often must provide
guarantees, letters of credit and collateral for our contractual commitments.
Sources of Liquidity
Historically, we have obtained cash from recourse and non-recourse
financings, from capital contributions and loans by PG&E Corporation, and from
distributions and fees from our subsidiaries and project affiliates. In many
cases, the loan, partnership and other agreements that apply to our
subsidiaries and project affiliates restrict these entities from distributing
cash to us unless, among other things, debt service, lease obligations, and any
applicable preferred payments are current, the applicable subsidiary or project
affiliate meets certain debt service coverage ratios, a majority of the
participants approve the distribution, and there are no events of default. In
addition, the subsidiaries that own our natural gas transmission facilities and
our energy trading businesses have been "ringfenced" and cannot pay dividends
to us unless the subsidiary's board of directors or board of control, including
its independent director, unanimously approves the dividend payment and unless
the subsidiary has either a specified investment grade credit rating or meets a
2.25 to 1.00 consolidated interest coverage ratio and a 0.70 to 1.00
consolidated leverage ratio.
Historically, we have borrowed funds from and loaned funds to PG&E
Corporation for specific transactions or other corporate purposes. These
intercompany loans accrued interest at PG&E Corporation's short-term borrowing
rates through December 31, 2000, and accrued interest at a floating LIBOR-based
rate from January 1, 2001. As of June 30, 2001, we had a net outstanding loan
balance payable to PG&E Corporation of $355 million. PG&E Corporation also has
contributed equity capital to finance a portion of the acquisition and
construction costs of various capital projects and for other corporate
purposes. We have, in turn, paid dividends to PG&E Corporation.
In addition, PG&E Corporation historically has provided us credit support
for a range of our contractual commitments. With respect to our generating
facilities, this credit support has included agreements to infuse equity in
specific projects when these projects begin operations or when we purchase a
project that we have leased. PG&E Corporation also has provided guarantees of
our obligations under several long-term tolling arrangements and as collateral
for our commitments under various energy trading contracts entered into by our
energy trading operations. PG&E Corporation also provided guarantees to support
several letter of credit facilities issued by our energy trading operations to
provide short-term collateral to counterparties. As of
45
August 20, 2001, except for approximately $16 million of guarantees relating to
various energy trading master contracts (for which PG&E Corporation's total
exposure was approximately $320,000), we had replaced all PG&E Corporation
equity infusion agreements and guarantees with our own equity infusion
agreements, guarantees or other forms of security.
We do not intend to lend to or borrow from PG&E Corporation in the future
nor do we expect to receive any future capital contributions (either directly
or to our subsidiaries) or guarantees from PG&E Corporation. We may not pay
dividends to LLC unless our board of directors, including our independent
director, unanimously approves the dividend payment and unless we have either a
rating of Baa3 from Moody's or BBB- from Standard & Poor's or meet a 2.25 to
1.00 consolidated interest coverage ratio.
In connection with the replacement of PG&E Corporation guarantees with our
own, and with the continued growth of our energy trading and marketing
positions, we have experienced a substantial increase in the amount of cash we
have been required to place on deposit with various counterparties without a
commensurate increase in margin deposits received from counterparties. Our cash
margin deposits outstanding to counterparties net of cash margin received from
counterparties increased from $10 million as of December 31, 2000 to $92
million as of June 30, 2001. On June 15, 2001, we established a $550 million
revolving credit facility (which includes the ability to issue letters of
credit) with a syndicate of banks to support our energy trading operations and
for other working capital requirements. On June 30, 2001, $111 million of
letters of credit were outstanding under this facility and there were no
borrowings under this facility. This new $550 million facility has an initial
364-day term that expires on June 14, 2002.
In addition, we maintain various revolving credit facilities at subsidiary
levels which currently are available to fund our capital and liquidity needs.
Our generation operation maintains one $500 million revolving credit facility,
one $550 million revolving credit facility and one $100 million revolving
credit facility. The $500 million facility, a 364-day facility, expires at the
end of August 2001 (but may be extended for up to two years or until our new
facility is increased), and the $550 million facility, a five-year facility,
expires in August 2003. The $100 million facility expires in September 2003.
GTN maintains a $100 million revolving credit facility that expires in May 2002
(but may be extended for successive one-year periods). Outstanding loans on all
four facilities are charged LIBOR-based interest rates with an interest rate
spread over LIBOR tied to the credit rating of the applicable subsidiary and
the amount drawn on the facility. All four of the revolving credit facilities
can be used to back commercial paper that has a P2 rating from Moody's and an
A2 rating from Standard & Poor's. As of June 30, 2001, we had borrowed $520
million against our total $1.25 billion borrowing capacity under these
facilities. In addition, as of June 30, 2001, approximately $33 million of
letters of credit were outstanding under these facilities.
On May 22, 2001, we completed the offering of the original notes and
received net proceeds after debt discount and note issuance costs of
approximately $974 million. We used the net proceeds to pay down $630 million
of our revolving credit facilities and will use the remainder to pay the
approximately $90 million purchase price for our Mountain View wind facility,
fund working capital requirements, make investments in generating and pipeline
assets or for other corporate purposes. The original notes have an aggregate
principal amount of $1 billion, bear interest at 10.375% per annum and mature
on May 16, 2011.
On May 29, 2001, we established a revolving credit facility of up to $280
million to fund turbine payments and equipment purchases associated with our
generation facilities. This facility expires on December 31, 2003.
We are planning by the end of 2001 to increase our new $550 million facility
to $1.25 billion that will rank equally with the notes and, if our new credit
facility is increased to $1.25 billion, we have agreed to terminate the $500
million and the $550 million facilities described above. Upon increase, we
expect a portion of this facility will have a 364-day term and a portion will
have a two-year term. These portions may be structured as separate facilities.
The $1.25 billion credit facility has received preliminary ratings of BBB from
Standard and Poor's and Baa2 from Moody's, subject to review of final
documentation.
46
We have made substantial commitments and have numerous options to increase
our owned and controlled generating and pipeline capacity. In order to finance
planned growth in our owned and controlled generating and pipeline capacity and
our energy marketing and trading operations, we intend to implement a financing
strategy with the following key elements:
. maintain our existing investment grade rating--investment grade ratings
are particularly important to efficiently meet the credit and collateral
requirements associated with our trading activities;
. maintain our short-term debt facilities so that we generally have
sufficient liquidity to meet short-term cash needs and to efficiently
provide letters of credit to replace cash margin deposits;
. continue to use longer-term capital market debt to refinance shorter-term
debt;
. increase our use of loans and financings secured by multiple generating
facilities;
. pursue the sale of some of our owned generating facilities to strategic
and financial investors and enter into leases and/or tolling agreements
that will allow us to continue to control the output of these facilities;
and
. issue preferred or common equity.
Under the terms of PG&E Corporation's credit facility, our issuance of
equity, other than through an initial public offering, would be a default
unless the lenders consented. In addition, following an initial public
offering, PG&E Corporation would be required to reduce the amount of its term
loans to an aggregate of $500 million. Neither we nor PG&E Corporation require
approval of lenders to transfer to third parties all or a portion of the equity
of a number of lower level subsidiaries, including those holding our advanced
development projects, so long as we retain the proceeds as cash, use the
proceeds to pay down debt or reinvest the proceeds in our business.
Possibilities for raising additional equity include an initial public offering,
a private placement of our common and/or preferred equity, the sale of a
minority interest in a subsidiary holding our integrated energy and marketing
business segment, and the issuance of equity in an entity that would be formed
to hold a selected group of generating projects, primarily including projects
currently in advanced development.
Under various guarantees that we have provided, including the guarantees
issued to support Lake Road, La Paloma and Harquahala, as well as our new $280
million equipment purchase revolving credit facility, if our credit rating were
downgraded below investment grade, we would be required to provide alternative
credit enhancements such as guarantees of our investment grade subsidiaries,
letters of credit or cash collateral. If we were unable to provide such
enhancements within 30 days, the guaranteed loans would be due and payable
within five days. If such loans were not repaid within this period, the lenders
to those projects would have the right to stop lending under the applicable
financing agreements, we would be required to repay all the loans and the
lenders could foreclose on the project assets and call on our guarantees. If we
were unable to perform under these guarantees, we could be in default under all
of our senior obligations, including the original notes and exchange notes,
which could materially harm our business. In addition, we or various of our
subsidiaries have guaranteed the financial performance of our trading
subsidiaries to various trading counterparties. If we fail to maintain an
investment grade rating, alternative security would have to be posted in the
form of other investment grade guarantees, letters of credit or cash
collateral. If we are unable to provide these enhancements, certain valuable
contractual assets could be lost and certain trading obligations could be
accelerated which could materially harm our business.
Commitments and Capital Expenditures
The projects that we develop typically require substantial capital, and we
have made a number of firm commitments associated with our planned growth of
owned and controlled generating facilities, as well as our pipelines. These
include commitments for projects under construction, commitments for the
acquisition and maintenance of equipment needed for projects under development,
payment commitments for tolling arrangements, and forward sale and purchase
commitments associated with our energy marketing and trading activities.
47
Generating Projects in Construction
We currently own, control, or will own the output of ten generating
facilities under construction: Lake Road, La Paloma, Athens, Plains End,
Harquahala, Mountain View, Covert, Caledonia, Southaven and Liberty Electric.
The construction costs of both Lake Road and La Paloma are being financed
under separate lease facilities with substantially similar terms. Under these
arrangements, a third party owner/lessor is financing construction of each
facility while we are serving as construction agent. Once each facility is
completed, a two-year and three-year operating lease, respectively, for the
projects will begin. Our obligations under these leases will be determined at
the completion of construction and are estimated to begin in early 2002 (for
Lake Road) and mid-2002 (for La Paloma). At the end of each lease, we have the
option to extend the lease at fair market value, purchase the project, or act
as remarketing agent for the lessor for a sale of the project to a third party.
If we act as remarketing agent for the lessor, then we are obligated to the
lessor for up to 85% of the project's costs if the proceeds from the sale are
less than the lessor's book value. We have committed to the project lenders to
contribute equity of up to $230 million for Lake Road and up to $379 million
for La Paloma at the termination of their respective leases. In addition, we
have agreed with the project lenders that we will purchase the portion of
project loans secured by our guarantees on the later of the completion of
project construction or March 31, 2003.
In addition, we have entered into agreements with a trust that will own and
finance turbine payments and project-related costs for the Harquahala facility.
The trust has financing commitments of $122 million from debt investors
currently backed by agreements from us to contribute up to $122 million in
equity. As of June 30, 2001, the trust had incurred $108 million of project-
related expenditures. We are in the process of arranging a $1.85 billion multi-
project financing facility that would provide construction financing for
Harquahala, Athens and Covert. If this facility is implemented, we would use
proceeds from facility loans to purchase the Harquahala project from the trust.
In addition, the completed Millennium facility would be contributed as equity
to this pool of assets. We would provide additional equity contributions or
commitments as required. Loan repayment would be secured by all of the projects
in the pool and, other than our equity infusion agreements, would be non-
recourse to us. We expect to implement this facility before the end of 2001. We
also have agreed to pay capital costs in excess of a predetermined amount
required to complete construction of Covert and Harquahala.
We currently are funding progress payments for three turbines and related
project costs for our Athens facility through our existing revolving credit
facilities and from available cash. Through June 30, 2001, we had made payments
totaling $236 million for Athens. We entered into an agreement with Bechtel for
the construction of the Athens facility and released Bechtel to commence
construction at the end of May 2001. We have guaranteed approximately $21
million with respect to various Athens contractors.
We intend to finance the expected $81 million total cost of the Plains End
project with available cash and an approximately $65 million loan, secured
solely by the project, that we are in the process of arranging. As of June 30,
2001, we had guaranteed $27 million with respect to Plains End contractors and
power purchasers.
In connection with the Southaven project financing and our tolling
agreement, we have provided to the owner of that project, a subsidiary of
Cogentrix, a commitment to provide a subordinated loan of up to $75 million at
the time of completion of the project, if at that time we are not rated at
least Baa2 by Moody's and BBB by Standard & Poor's, with at least a stable
outlook.
Under our acquisition agreements for Mountain View, we will pay the purchase
price, currently estimated to be approximately $90 million, when the project is
complete, which is expected to be during the second half of 2001. We expect to
finance this purchase from the net proceeds of the offering of the original
notes, or to the extent those net proceeds were used in the interim to pay down
our revolving credit facilities, to finance it with the increased borrowing
capacity under our revolving credit facilities. Finally, under our tolling
agreement for
48
Liberty Electric, the owner is obligated to construct and place the facility in
service at its own expense. Our obligations to make fixed payments commence
only when the facility has achieved commercial operations, which we expect to
occur in 2002. As of June 30, 2001, we had guaranteed $87 million of the
purchase price.
Turbine Purchase Commitments and Generating Projects in Development
We have entered into commitments to ensure that we have the turbines and
other equipment necessary to meet our growth plans. Most significantly, we have
secured contractual commitments and options for 60 new advanced technology
combustion turbines representing 20,218 MW of net generating capacity. Nineteen
of these turbines, representing approximately 6,189 MW, are for generating
facilities under construction or recently placed in operation as of August 15,
2001. Subject to maintaining our credit quality and raising necessary capital,
we expect to deploy the balance on projects which we are developing.
In 2000, we entered into agreements with two master turbine trusts, special
purpose entities created to own and facilitate the development, construction
financing and leasing of generating facilities that will use 44 turbines to be
manufactured by General Electric and Mitsubishi. PG&E Corporation and we
committed to provide up to $314 million in equity to meet our obligations to
the trusts. As of May 31, 2001, the trusts had incurred $216 million of
expenditures. We used $216 million of our new $280 million revolving credit
facility to purchase the turbines from the master turbine trusts. We also
provided guarantees to equipment vendors in an aggregate amount in excess of
$150 million. Our equity commitments to the master turbine trusts have been
terminated.
We have entered into, or agreed to enter into, long-term service agreements
with the turbine manufacturers for the maintenance and repair of the 60
turbines for which we have secured contractual commitments and options. These
agreements also cover maintenance and repair of the generating facilities in
which the turbines will be used. We expect our commitments under these long-
term service agreements will expire at various times through 2021 and will
total approximately $3.5 billion. Actual payments under these agreements will
vary depending on the output generated by the facilities and other operating
factors.
We also have entered into a number of long-term tolling agreements. As of
June 30, 2001, our annual estimated committed payments under these contracts
ranged from $8.7 million to $294.6 million, resulting in total committed
payments over the next 27 years of approximately $6.0 billion. We provide
guarantees under each of these agreements and receive guarantees from our
counterparties. As of June 30, 2001, we had provided or committed to provide
guarantees to support these tolling agreements totaling up to $1.1 billion.
On December 6, 2000, we agreed to sell one of our development projects. This
sale closed on July 10, 2001, and we recorded an after-tax gain of
approximately $14 million to be recognized in the third quarter. Also on
December 6, 2000, we entered into a tolling agreement that will entitle us to
receive up to 250 MW of the project's production for a ten-year period
commencing at commercial operation. As part of this tolling arrangement, we
agreed to provide guarantees of up to $40 million, which are included in the
total guarantees as of December 31, 2000.
Other Commitments and Plans
Our energy marketing and trading operations have a number of outstanding
commitments under various energy trading master contracts, for which we or PG&E
Corporation have provided guarantees. As of August 20, 2001, the face value of
these guarantees totaled $2.37 billion. Of this amount, we provided
approximately $2.35 billion and PG&E Corporation provided approximately $16
million (for which PG&E Corporation's total exposure was approximately
$320,000). We continue to negotiate with our trading counterparties to replace
the remaining PG&E Corporation guarantees with our own.
We also have other long-term contractual commitments associated with our
existing generation and trading business, including power purchase agreements,
gas supply and transportation agreements, operating lease
49
agreements and agreements for payments in lieu of property taxes. For all of
these long-term contractual commitments that were in place as of December 31,
2000, the future minimum annual commitments were as follows:
Commitments
Year (in millions)
---- -------------
2001........................................................... $ 429
2002........................................................... 477
2003........................................................... 483
2004........................................................... 474
2005........................................................... 400
Thereafter..................................................... 3,323
------
$5,586
======
In April 2001, we entered into an agreement for pipeline capacity with El
Paso Natural Gas. This capacity will be used principally to supply gas to serve
our western portfolio, including Harquahala, La Paloma and Meadow Valley and
the Otay Mesa tolling agreement. Under the terms of the agreement, our future
minimum annual commitments are $14 million in 2001, $25 million per year from
2002 to 2005 and a total of $93 million thereafter.
We plan to expand the capacity of our GTN pipeline by at least 500 million
cubic feet per day by the end of 2004. We expect the first phase of this
expansion, which will amount to approximately 220 million cubic feet per day,
to be completed by the end of 2002 and to cost approximately $122 million. As a
result of an open season we recently completed, we intend to complete a second
phase of this expansion for approximately 240 million cubic feet per day of
additional capacity at a cost of approximately $150 million, to be completed at
the end of 2003. We expect to fund these expansions from the issuance of
additional GTN debt, and available cash or draws on available lines of credit.
In addition, we have entered into joint development of a new 500 million
cubic feet per day gas pipeline, North Baja, to deliver natural gas to Northern
Mexico and Southern California. The North Baja project is expected to be
completed by the end of 2002. We own all of the United States section of this
cross-border project. Our share of the costs to develop this project will be
approximately $146 million. We expect to fund this project from the issuance of
non-recourse debt, and available cash or draws on available lines of credit. In
connection with the North Baja project, we have issued $47 million in
guarantees as of June 30, 2001.
We anticipate spending up to approximately $330 million, net of insurance
proceeds, through 2006 for environmental compliance at currently operating
facilities. We believe that a substantial portion of this amount will be funded
from our operating cash flow. This amount may change, however, and the timing
of any necessary capital expenditures could be accelerated in the event of a
change in environmental regulations or the commencement of any enforcement
proceeding against us.
We purchased Attala, a partially constructed power plant, in September 2000
for $311 million. Under the purchase agreement, we also prepaid the remaining
construction costs to the seller, who was obligated to complete construction
and deliver a fully operational facility to us by July 1, 2001. Attala
commenced commercial operation in June 2001. We funded the initial purchase
price in part with a $309 million non-recourse, secured short-term loan from
PG&E Corporation. We intend to sell the project and lease it back. We expect to
use the proceeds of the sale to retire the loan from PG&E Corporation or to
otherwise refinance the project and satisfy the PG&E Corporation loan by the
end of 2001.
We have recently agreed to supply the full service power requirements of the
city of Denton, Texas, for a period of five years beginning July 1, 2001. The
city of Denton's peak load forecast is 280 MW in 2001 increasing to 314 MW over
the term of the contract. Our supply obligation to the city is net of about 97
MW of
50
generation entitlements still retained by the city (plus 40 MW of purchased
power that the city has assigned to us for summer 2001). In connection with the
power supply agreement, we recently acquired the 178 MW gas-fired Spencer
station from the city and have also agreed to acquire two small hydroelectric
facilities from the city. The total consideration of approximately $12 million
was allocated between the fair value of the power supply contract, recorded as
an intangible asset, and property, plant and equipment.
We have decided to evaluate strategic options for, including the possible
sale of, our dispersed generation business unit. This unit develops, constructs
and operates small gas-fired peaker facilities, including the 144 MW Ohio
Peakers, which is in operation, and the 111 MW Plains End project in Colorado,
which is in construction. The unit also owns numerous used turbines, which are
in various stages of refurbishment. The dispersed generation business unit had
approximately $159 million of assets as of June 30, 2001.
Operating Activities
During the six months ended June 30, 2001, we provided net cash of $19
million in operating activities. Net cash from operating activities before
changes in other working capital accounts was $39 million, driven primarily by
our increased net income. Our net cash outflow related to certain other working
capital accounts was $20 million, driven primarily by an increase in margin
deposits related to our trading activities.
During 2000, we generated net cash from operating activities of $163
million. Net cash from operating activities before changes in other working
capital accounts was $267 million. Our increase in certain other working
capital accounts was $104 million, driven primarily by growth in our energy
trading and marketing activities.
During 1999, we generated net cash from operations of $74 million. Net cash
from operating activities before changes in other working capital accounts was
$198 million. Our increase in certain other working capital accounts was $124
million, driven primarily by growth in our energy trading and marketing
activities.
During 1998, we generated net cash from operations of $64 million. Net cash
from operating activities before changes in other working capital accounts was
$272 million. Our increase in certain other working capital accounts was $208
million, due principally to decreases in accounts payable and accrued
liabilities and increases in certain current assets.
Investing Activities
During the six months ended June 30, 2001, we used net cash of $523 million
in investing activities. Our cash outflows from investing activities were
primarily attributable to capital expenditures on generating projects in
construction or advanced development, and turbine prepayments.
During 2000, we used net cash of $144 million in investing activities. Our
primary cash outflows from investing activities were for capital expenditures
of $312 million and the acquisition of Attala for cash of $311 million. These
outflows were partially offset by the receipt of $442 million in proceeds from
sales of assets and equity investments.
During 1999, we used net cash of $63 million in investing activities. Our
investing activities in 1999 consisted principally of $150 million in capital
expenditures, partially offset by proceeds from the sale of assets or equity
investments of $90 million.
During 1998, we used net cash of $1.3 billion in investing activities. Our
investing activities in 1998 included the acquisition of our New England
generating facilities for cash of approximately $1.7 billion. We also spent
$221 million on capital expenditures. These outflows were partially offset by
$479 million in proceeds from the sale and leaseback of one of our New England
generating facilities and $126 million in proceeds from the sale of our
Australian energy holdings.
51
Financing Activities
During the six months ended June 30, 2001, we provided net cash of $567
million in financing activities principally from the net proceeds related to
the original notes.
Net cash provided by financing activities was $491 million during 2000. Net
cash provided by financing activities resulted primarily from capital
contributions by PG&E Corporation of $608 million, partially offset by
distributions of $106 million and other items.
During 1999, net cash provided by financing activities was $49 million. This
amount includes borrowings and debt issuances totaling $360 million. We
declared and paid to PG&E Corporation a dividend of $111 million in 1999.
During 1999, we also repaid a total of $269 million of long-term debt,
including GTT mortgage bonds and senior notes.
During 1998, net cash provided by financing activities was $1.1 billion.
PG&E Corporation made capital contributions to us of $624 million, including
$425 million to fund the acquisition of our New England generating facilities
and to fund losses at our energy trading and marketing business and former
energy services business. In addition, we issued $378 million of long-term debt
and borrowed $193 million under revolving credit facilities. We declared and
paid dividends of $151 million in 1998.
Quantitative and Qualitative Disclosures about Market Risk
We have established a risk management policy that allows derivatives to be
used for both trading and non-trading purposes (a derivative is a contract
whose value is dependent on or derived from the value of some underlying
asset). We use derivatives for hedging purposes primarily to offset our primary
market risk exposures, which include commodity price risk and interest rate
risk. Our foreign currency risk is not material. We also participate in markets
using derivatives to gather and use market intelligence, create liquidity and
maintain a market presence. Such derivatives include forward contracts,
futures, swaps, options and other contracts.
We may only engage in the trading of derivatives in accordance with policies
and procedures established by our risk management committee, as well as with
policies set forth by the corporate risk policy committee of PG&E Corporation.
Trading is permitted only after our risk management committee authorizes such
activity subject to appropriate financial exposure limits. Both committees are
comprised of senior executive officers.
Commodity Price Risk
Commodity price risk is the risk that changes in market prices will cause
our earnings, value and cash flows to vary from expectations. We are primarily
exposed to the commodity price risk associated with energy commodities such as
electric power and natural gas. Therefore, our price risk management activities
primarily involve buying and selling fixed-price commodity commitments into the
future. Net open positions often exist or are established due to our assessment
of and response to changing market conditions. To the extent that we have an
open position, we are exposed to the risk that fluctuating market prices may
adversely impact our financial results.
We prepare a daily assessment of our commodity price risk exposure using
value-at-risk and other methodologies that simulate future price movements in
the energy markets to estimate the size and probability of future potential
losses. We quantify market risk using a variance/co-variance value-at-risk
model that provides a consistent measure of risk across diverse energy markets
and products. The use of this methodology requires the selection of a
confidence level for losses and a portfolio holding period. In addition,
assumptions are made regarding volatility of prices, price correlations across
products and markets and market liquidity.
We utilize historical data for calculating the price volatility of our
positions and how likely the prices of those positions will move together. The
model includes derivative and commodity investments in our trading and non-
trading portfolios, and also includes in non-trading in all periods, the
physical positions related to the
52
New England assets. We express value-at-risk as a dollar amount of the
potential reduction in the fair value of our portfolio from changes in prices
over a one-day holding period based on a 95% one-tailed confidence level.
Therefore, there is a 5% probability that our portfolio will incur a loss in
one day greater than our value-at-risk. For example, if value-at-risk is
calculated at $5.0 million, we can state with a 95% confidence level that if
prices moved against our positions, the reduction in the value of our portfolio
resulting from such one-day price movements would not exceed $5.0 million.
Based on value-at-risk analysis of the overall commodity price risk exposure of
the trading business on June 30, 2001, we did not anticipate a materially
adverse effect on our consolidated financial statements as a result of market
fluctuations.
The following table illustrates the value-at-risk for our daily commodity
price risk exposure as of December 31, 1998, 1999 and 2000 (in millions), with
Trading representing the combined results for all of our trading operations:
Commodity
Price
Risk Type of Activity Value-at-Risk Average Low High
--------- ---------------- ------------- ------------- ------------- -------------
12/31/00 Trading 11.5 6.8 5.5 12.3
Non-Trading 8.8 9.5 7.6 11.1
12/31/99 Trading 4.4 4.3 1.3 6.2
Non-Trading -- 0.6 -- 1.7
12/31/98 Trading 6.2 4.5 2.5 6.2
Non-Trading 0.2 not available not available not available
Our daily value-at-risk commodity price risk exposure as of June 30, 2001
was $15 million for trading activities and $12 million for non-trading
activities. The increase in non-trading value-at-risk as of June 30, 2001 from
December 31, 2000 is due to the inclusion of additional hedges for asset
positions. If the underlying physical positions for all assets were included at
June 30, 2001, the non-trading value-at-risk would have been $36 million.
This methodology has several limitations as a measure of portfolio risk,
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements and the inability to address the risk
resulting from intra-day trading activities.
Interest Rate Risk
Floating rate exposure measures the sensitivity of corporate earnings and
cash flows to changes in short-term interest rates. This exposure arises when
short-term debt is rolled over at maturity, when interest rates on floating
rate notes are periodically reset according to a formula or index, and when
floating rate assets are financed with fixed rate liabilities. We manage our
exposure to short-term interest rates by using an appropriate mix of short-term
debt, long-term floating rate debt, and long-term fixed rate debt.
Financing exposure measures the effect of an increase in interest rates that
may occur related to any planned or expected fixed rate debt financing. This
includes the exposure associated with replacing debt at maturity. We will hedge
financing exposure in situations where the potential impairment of earnings,
cash flows, and investment returns or execution efficiency, or external factors
(such as bank imposed credit agreements) necessitate hedging.
We evaluate the short-term and long-term interest rate exposures and
consider our overall corporate finance objectives when considering proposed
hedges. We evaluate the use of the following interest rate instruments to
manage our interest rate exposure: interest rate swaps, interest rate caps,
floors, or collars, swaptions, or interest rate forwards and futures contracts.
Interest rate risk sensitivity analysis is used to measure our interest rate
price risk by computing estimated changes in cash flows as a result of assumed
changes in market interest rate. If interest rates changed by 1% for all
variable rate debt, the change would affect net income by approximately $6
million, based on variable rate debt and derivatives and other interest rate
sensitive instruments outstanding at June 30, 2001.
53
Foreign Currency Risk
Economic exposure measures the change in value that results from changes in
future operating or investing cash flows caused by the timing and level of
anticipated foreign currency cash flows. Economic exposure includes the
anticipated purchase of foreign entities, anticipated cash flows and projected
revenues and expenses denominated in a foreign currency.
Transaction exposure measures changes in the value of current outstanding
financial obligations already incurred, but not due to be settled until some
future date. This includes the agreement to purchase a foreign entity in a
currency other than the U.S. dollar, an obligation to infuse equity capital
into a foreign entity, and foreign currency denominated debt obligations, as
well as actual non-U.S. dollar cash flows such as dividends declared but not
yet paid.
Translation exposure measures potential accounting-derived changes in
owners' equity that result from the need to translate foreign currency
financial statements of affiliates into a single reporting currency in order to
prepare a consolidated financial statement for us.
We use forwards, swaps, and options to hedge foreign currency exposures.
Based on the sensitivity analysis at June 30, 2001, a 10% devaluation of the
Canadian dollar would not have had a material impact on our consolidated
financial statements.
New Accounting Standards
We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS Nos. 137 and 138 as of January 1, 2001. This
standard requires us to recognize all derivatives, as defined in SFAS No. 133,
on our balance sheet at fair value. Derivatives, or any portion thereof, that
are not effective hedges must be adjusted to fair value through income. If
derivatives are effective hedges, depending on the nature of the hedges,
changes in the fair value of derivatives either will offset the change in fair
value of the hedged assets, liabilities, or firm commitments through earnings,
or will be recognized in other comprehensive income, a component of equity,
until the hedged items are recognized in earnings. The transition adjustment to
implement the new standard was an immaterial adjustment to net income and a
negative adjustment of approximately $333 million (after tax) to other
comprehensive income, a component of stockholder's equity. This transition
adjustment, which relates to hedges of interest rate, foreign currency and
commodity price risk exposure, was recognized as of January 1, 2001 as a
cumulative effect of a change in accounting principle.
We also have certain derivative commodity contracts for the physical
delivery of purchase and sale quantities transacted in the normal course of
business. These derivatives are exempt from the requirements of SFAS No. 133
under the normal purchases and sales exception, and thus are not reflected on
the balance sheet at fair value. In June 2001, the Financial Accounting
Standards Board, or the FASB, approved an interpretation issued by the
Derivatives Implementation Group, or DIG, that changes the definition of normal
purchases and sales for certain power contracts. The FASB is currently
considering another DIG interpretation that would change the definition of
normal purchases and sales for certain other commodity contracts. Certain of
our derivative commodity contracts may no longer be exempt from the
requirements of SFAS No. 133. We are evaluating the impact of the
implementation guidance on our financial statements and will implement this
guidance, as applicable, on a prospective basis.
The SEC issued Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB
No. 101), on December 3, 1999. SAB No. 101 summarizes some of the staff's views
in applying generally accepted accounting principles to revenue recognition.
The consolidated financial statements reflect the accounting principles
provided in SAB No. 101.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This
standard prohibits the use of pooling-of-interests method of accounting for
business combinations initiated after June 30, 2001 and applies
54
to all business combinations accounted for under the purchase method that are
completed after June 30, 2001. We do not expect that implementation of this
standard will have a significant impact on our financial statements.
Also in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This standard eliminates the amortization of goodwill, and
requires goodwill to be reviewed periodically for impairment. This standard
also requires the useful lives of previously recognized intangible assets to be
reassessed and the remaining amortization periods to be adjusted accordingly.
This standard is effective for fiscal years beginning after December 15, 2001,
for all goodwill and other intangible assets recognized on our statement of
financial position at that date, regardless of when the assets were initially
recognized. We have not yet determined the effects of this standard on our
financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This standard is effective for fiscal years beginning after June
15, 2002, and provides accounting requirements for asset retirement obligations
associated with tangible long-lived assets. We have not yet determined the
effects of this standard on our financial statements.
55
BUSINESS
Overview
We are an integrated energy company with a strategic focus on power
generation, greenfield development, natural gas transmission and wholesale
energy marketing and trading in North America. We have integrated our
generation, development and energy marketing and trading activities to increase
the returns from our operations, identify and capitalize on opportunities to
increase our generating and pipeline capacity, create energy products in
response to dynamic markets and manage risks. We intend to expand our
generating and natural gas pipeline capacity and enhance our growth and
financial returns through our energy marketing and trading capabilities.
We own, manage and control the electric output of generating facilities in
targeted North American markets. As of June 30, 2001, we had ownership or
leasehold interests in 23 operating generating facilities with a net generating
capacity of 6,438 MW, as follows:
Primary % of
Number of Facilities Net MW Fuel Type Portfolio
- -------------------- ------ ----------- ---------
10............................................... 2,997 Coal/Oil 46.7
9............................................... 2,263 Natural Gas 34.9
3............................................... 1,166 Water 18.2
1............................................... 12 Wind 0.2
---
----- -----
23............................................... 6,438 100.0
In addition, we have seven facilities totaling 5,480 MW in construction, and
we control through various arrangements an additional 518 MW in operation and
2,188 MW in construction, giving us a total owned and controlled generating
capacity in operation or construction of 14,624 MW. We also own or control
7,559 MW of primarily baseload, natural gas-fired projects in advanced
development. Through these projects, we intend to further grow and regionally
diversify our generating portfolio to at least 22,183 MW by the end of 2004.
Our natural gas transmission business consists of North American pipeline
facilities, including our Gas Transmission Northwest, or GTN, pipeline and a
North Baja pipeline under development. GTN consists of over 1,300 miles of
natural gas transmission pipe with a capacity of 2.7 billion cubic feet of
natural gas per day. This pipeline is the only interstate pipeline directly
linking the natural gas reserves in Western Canada to the gas markets in
California and parts of the Pacific Northwest. GTN is currently operating at or
near capacity and we plan to expand its capacity by at least 500 million cubic
feet per day by December 31, 2004. We also are in advanced stages of
development of a North Baja pipeline that will link the gas constrained markets
of Northern Mexico and Southern California to the Southwest and Rocky Mountain
natural gas supply basins. The North Baja pipeline will have an expected
initial capacity of 500 million cubic feet per day by late 2002. We have also
initiated development of a Washington lateral pipeline that would originate at
the GTN mainline system near Spokane, Washington and extend approximately 260
miles to western Washington.
We believe our energy marketing and trading operations enhance the growth
and profitability of our owned and controlled generation and pipeline assets.
Our energy marketing and trading operations manage fuel supply procurement and
the sale of electrical output of our owned and controlled generating facilities
as an integrated portfolio with our trading positions. We believe our
integrated portfolio approach reduces our exposure to market risks and enhances
the growth and stability of our earnings through economies of scale,
diversified product offerings, increased market insight, optimized capacity
utilization and more effective risk management. Our energy marketing and
trading operations also provide us with valuable market knowledge to identify
and capitalize on opportunities to develop, acquire and contractually control
additional generating, natural gas pipeline and storage capacity. During 2000,
we sold 283 million MW hours of power and an average of 6.5 billion cubic feet
of natural gas per day.
56
During 2000, 33% of our Adjusted EBITDA came from GTN, 26% came from USGen
New England, 18% came from our independent power projects and 23% came from all
other activities, net of general and administrative expenses, including energy
marketing and trading.
Strategy
During 2000, an estimated $228 billion of electricity and $105 billion of
natural gas was purchased by end-users in the United States. The electric and
natural gas industries are undergoing rapid transformation due to customer
demand for enhanced services and competitive markets. In response to this
demand, initiatives to increase competitive participation in the electric and
natural gas industries have been and are continuing to be adopted at both the
state and federal level. These initiatives are fundamentally changing the
ownership and development of energy assets, the markets for fuels and
electricity and the relationships between energy providers and end-users. The
existing energy market has become a more competitive market where many end-
users or their direct suppliers are now able to purchase electricity and
natural gas from a variety of providers, including non-utility generators,
power and natural gas marketers and utilities.
We believe restructuring of the energy market and the growing demand for
electric power and natural gas in the United States create attractive
opportunities for integrated energy companies like ours. Our objective is to
become a leading integrated energy company with a strong national presence by
taking advantage of these market opportunities. Our strategy to achieve this
objective includes the following components:
Expand Our Generating and Pipeline Capacity. We intend to expand our
generating and pipeline capacity through:
. Greenfield Development. We intend to increase our generating capacity
through greenfield development of gas-fired generating facilities
strategically located in our targeted North American markets. We
currently have 6,234 MW of generating projects in advanced development in
the United States. We have secured the turbines and sites necessary to
complete these development projects over the next four years. We also
have options to acquire turbines and a site inventory of early stage
developments to support an additional 7,795 MW of projects.
. Contractual Control. We intend to increase our control of the electric
output of generating facilities in strategic markets through various
contractual arrangements. We use our trading, marketing, financing and
development expertise to successfully identify, negotiate and structure
these contractual arrangements. We currently control generating capacity
in operation, construction or advanced development totaling 4,031 MW. In
order to increase capital available for further development, while
maintaining control of our generating capacity, we also intend to sell
some of our owned generating facilities to strategic and financial
investors and enter into long-term contracts that will allow us to use
some or all of the facility's capacity to convert our fuel to
electricity. We also intend to enter into additional long-term contracts
to control the supply, transportation and storage of the natural gas
required by our generating facilities.
. Gas Transmission Growth. We intend to expand the capacity of our existing
pipeline systems and pursue opportunities to construct additional natural
gas pipelines and storage facilities. We plan to expand the capacity of
our GTN pipeline by at least 500 million cubic feet per day by the end of
2004. We also plan to complete our North Baja pipeline, which will have
an expected initial capacity of 500 million cubic feet per day, by late
2002. We also expect to pursue further our Washington lateral pipeline
opportunities.
. Strategic Transactions. We intend to identify and pursue strategic
acquisitions that expand and complement our core operations. We have a
disciplined approach to acquisitions that emphasizes strong financial
returns and tangible operating benefits, such as immediate access to
generating capacity, customers or fuel diversity that cannot be attained
through greenfield development, contractual control or expansion of
existing facilities. We also expect to periodically divest assets to
adjust our regional portfolios and increase the availability of capital
for further growth.
57
Expand Our Presence in Targeted Regions. We intend to expand our presence in
targeted regions to increase our operational flexibility, create economies of
scale, diversify our geographic presence, enhance our local market insight and
improve our ability to create diverse energy products. We have established a
strong regional presence in the Northeast and we are strengthening our presence
in the midwestern, southern and western regions of the United States through
expanded energy marketing and trading activities and development and
contractual control of generating capacity in these regions.
Expand Our Integrated Energy Marketing and Trading Operations. We intend to
grow our integrated energy marketing and trading operations to enhance and
optimize the financial performance of our owned and controlled generating
facilities, transmission rights and storage facilities, and to manage
associated risks. We also intend to expand and diversify our product offerings
to satisfy the rapidly evolving needs of our integrated operations and our
expanding customer base.
Pursue Operational Excellence. We continually seek to maximize the revenue
potential of our integrated operations and minimize our operating and
maintenance expenses and fuel costs. We believe that our continued success in
achieving these operational goals will improve the earnings of our generating
facilities by increasing the percentage of hours that they are available to
generate power, particularly during peak energy price periods. We also intend
to capitalize on e-commerce applications in order to lower our costs.
Manage Our Growth to Maintain Credit Quality. Through our development
activities and our turbine options, we have the ability to rapidly expand our
generating capacity. In order to maintain our current credit quality while
constructing and placing in operation all of our 6,234 MW of owned power
generating projects in advanced development on our desired schedule, we would
require additional equity capital from third parties, which equity could
include an initial public offering of our common stock. We intend to raise
equity as required to maintain our credit quality while executing our growth
strategy, timing our growth to coincide with the availability of capital.
Our Competitive Strengths
We believe that we are well positioned to execute our strategy as a result
of the following competitive strengths:
Integrated Operations. We believe we are one of the few unregulated energy
companies that has fully integrated its greenfield development, power
generation, energy marketing and trading and risk management operations. We
believe our integrated approach provides us with significant competitive
advantages, including:
. Economies of Scale. We realize economies of scale by aggregating the
electric output and fuel requirements of our generating facilities with
our trading positions. In this way, we maximize our ability to negotiate
the best prices for our output and obtain fuel at the lowest cost.
. Superior Market Insight and Optimized Capacity Utilization. Our energy
marketing and trading operations provide our generating facilities with
real-time market information, including energy demand levels, supply
availability, electric and fuel prices, weather forecasts and the
anticipated timing and duration of peak demand periods. Our generating
facilities provide our marketing and trading operations with operating
information, including facility availability, production levels and
unanticipated outages. This real-time exchange of market and operating
information allows us to optimize our capacity utilization and increase
our financial returns under varying market conditions.
. Diverse Product Offerings. Our diverse portfolio of owned and controlled
generating facilities and physical and financial trading positions allow
us to offer our customers highly customized products with higher margins
and lower risk. For example, we offer contracts that can be tailored to
track electric or gas demand throughout the day, season or year, electric
or gas contracts in less developed competitive markets and other
solutions in response to the rapidly evolving needs of our customers.
58
. More Effective Risk Management and Controls. We believe we are one of the
first energy companies to integrate the input and output of our owned and
controlled generating facilities with our trading positions. We believe
the market insight we develop through our integrated operations results
in more sophisticated and effective management of market, credit,
operational and systems risks. On a daily basis, we manage our portfolio
in strict compliance with a predefined, approved set of policies and
procedures which set forth specific trading and credit limits. Our risk
management controls are designed to provide independent verification and
validation of all commercial activities.
Proven Power Plant Developer. We have a successful track record of
greenfield development of generating facilities. Since 1991, we have placed 21
generating facilities in construction with a net generating capacity of 9,037
MW. We believe our experienced management team's demonstrated ability to select
strategic sites, obtain necessary permits, garner local community support,
resolve environmental issues and manage construction provides us with a strong
basis for continued growth through greenfield development.
Strategically Located Pipelines. Our GTN pipeline is the only direct link
between the natural gas reserves in Western Canada and the gas markets in
California and parts of the Pacific Northwest. Our North Baja pipeline will
also be strategically located to connect the gas constrained markets of
Northern Mexico and Southern California with the Southwest and Rocky Mountain
natural gas supply basins. Our Washington lateral project would access markets
in the central and western portions of the state of Washington where there is a
need for gas pipeline infrastructure.
Efficient and Proven Operating Experience. Our generating facilities were
available to produce power 90% of the time during 2000 inclusive of the impact
of scheduled outages and major overhauls. Our new gas-fired facilities have
achieved an unanticipated outage rate of less than 1% and, in our older
recently acquired facilities, we reduced operating costs by nearly 50%, while
increasing the average availability of these units significantly. In
particular, we achieved a 95% commercial availability for these units in the
high value summer months of 2000. We also have been honored with more than 20
local, state and federal environmental awards. In addition, our GTN pipeline
achieved 95% availability during 2000.
Innovative Financing Expertise. We have extensive experience in structuring
innovative financings to provide capital to fund our growth. We have received
nine deal of the year awards from various international financial publications
for financings related to our generating facilities. Recently, the financing
for our Lake Road generating facility received three separate 1999 deal of the
year awards from Global Finance, Asset Finance International and Corporate
Finance magazines and our La Paloma lease and master turbine trust financings
won deal of the year awards from Project Finance International magazine in
2000. We believe we have the knowledge and skills necessary to optimize our
capital structure with on and off balance sheet financings.
Experienced Senior Management Team. Members of our senior management team
have substantial experience in the power and gas industry and include five
former presidents of energy companies.
Integrated Power Generating and Energy Marketing and Trading Business
We manage the operations, fuel supply and sale of electric output of our
owned and controlled generating facilities as an integrated portfolio with our
energy marketing and trading activities. We have a ten-year history of
successfully developing and operating generating facilities in North America
and, over the past five years, our energy marketing and trading activities have
contributed significantly to the growth of our revenues and net income. Our
energy marketing and trading operations also provide us with valuable market
knowledge to identify and capitalize on opportunities to develop, acquire and
contractually control additional generating facilities.
We had a net generating capacity of 6,956 MW produced by owned or controlled
power generating facilities operating in 14 states as of June 30, 2001. We plan
to increase our net beneficial interest in generating
59
capacity primarily through greenfield development of gas-fired generating
facilities and contractual control of generating capacity in targeted markets.
In addition, we own seven facilities totaling 5,480 MW in construction, and
control, through various arrangements, an additional 2,706 MW in operation or
construction giving us total owned and controlled capacity in operation or
construction of 14,624 MW. We also own or control 7,559 MW of primarily
baseload, natural gas-fired projects in advanced development, through which we
intend to further grow and regionally diversify our generating portfolio to at
least 22,183 MW by the end of 2004.
The following table summarizes our regional presence, dispatch type, fuel
type and ownership and control of operating generating capacity we plan to
achieve, subject to maintaining our credit quality, through greenfield
development of owned and controlled generating facilities and the applicable
percentages of the totals through December 31, 2004. Through our turbine
options, site inventory and acquisition and contracting capability, we expect
to have the opportunity to achieve increases beyond this level of capacity and
will do so if warranted.
December 31,
-------------------------------------------------------
2000 % 2001 % 2002 % 2003 % 2004 %
----- --- ----- --- ----- --- ------ --- ------ ---
(Numbers in MWs)
Regional Presence
New England........... 4,541 79% 5,741 73% 5,741 59% 5,741 34% 5,741 26%
Mid-Atlantic and New
York................. 544 9% 544 7% 1,112 12% 3,089 18% 4,292 19%
Midwest............... 160 3% 304 4% 304 3% 2,644 16% 4,889 22%
South................. 261 5% 787 10% 787 8% 2,407 14% 2,407 11%
West.................. 242 4% 486 6% 1,718 18% 3,060 18% 4,854 22%
----- --- ----- --- ----- --- ------ --- ------ ---
Total............... 5,748 100% 7,862 100% 9,662 100% 16,941 100% 22,183 100%
===== === ===== === ===== === ====== === ====== ===
Dispatch Type
Merchant Plants
Baseload............. 2,114 37% 3,677 47% 5,261 55% 12,111 71% 16,919 76%
Peaking/Intermediate.. 2,534 44% 2,907 37% 3,123 32% 3,552 21% 3,986 18%
Independent Power
Projects............. 1,100 19% 1,278 16% 1,278 13% 1,278 8% 1,278 6%
----- --- ----- --- ----- --- ------ --- ------ ---
Total............... 5,748 100% 7,862 100% 9,662 100% 16,941 100% 22,183 100%
===== === ===== === ===== === ====== === ====== ===
Fuel Type
Natural Gas........... 1,380 24% 3,428 44% 5,228 54% 12,507 74% 17,749 80%
Coal/Oil.............. 2,997 52% 2,997 38% 2,997 31% 2,997 18% 2,997 14%
Hydroelectric......... 1,166 20% 1,166 15% 1,166 12% 1,166 7% 1,166 5%
Other................. 205 4% 271 3% 271 3% 271 1% 271 1%
----- --- ----- --- ----- --- ------ --- ------ ---
Total............... 5,748 100% 7,862 100% 9,662 100% 16,941 100% 22,183 100%
===== === ===== === ===== === ====== === ====== ===
Ownership and Control
Owned/Leased.......... 5,230 91% 7,344 93% 8,576 89% 13,985 83% 18,152 82%
Controlled Output..... 518 9% 518 7% 1,086 11% 2,956 17% 4,031 18%
----- --- ----- --- ----- --- ------ --- ------ ---
Total............... 5,748 100% 7,862 100% 9,662 100% 16,941 100% 22,183 100%
===== === ===== === ===== === ====== === ====== ===
Our energy marketing and trading activities are focused in markets in which
we own or control generating facilities and in developed competitive markets.
During 2000, we sold 283 million MW hours of power and an average of 6.5
billion cubic feet of natural gas per day.
60
The following chart illustrates the growth of our combined electricity,
natural gas, coal and oil sales volumes since 1997.
Quadrillion Btu
1997 1998 1999 2000
-----------------------------------------------------------
Electricity 0.4190 1.0800 2.0000 2.8300
Natural Gas -- 3.5339 3.1580 2.4437
Coal 0.0645 0.1505 0.1849 0.5074
Oil -- 0.0240 0.0600 0.1530
In order to finance planned growth in our owned and controlled generating
and pipeline capacity and our energy marketing and trading operations, we
intend to implement a financing strategy with the following key elements:
. maintain our existing investment grade rating--investment grade ratings
are particularly important to efficiently meet the credit and collateral
requirements associated with our trading activities;
. maintain our short-term debt facilities so that we generally have
sufficient liquidity to meet short-term cash needs, and to efficiently
provide letters of credit to replace cash margin deposits;
. continue to use longer-term capital market debt to refinance shorter-term
debt;
. increase our use of loans and financings secured by multiple generating
facilities;
. pursue the sale of some of our owned generating facilities to strategic
and financial investors and enter into leases and/or tolling agreements
that will allow us to continue to control the output of these facilities;
and
. issue preferred or common equity.
Under the terms of PG&E Corporation's credit facility, our issuance of
equity, other than through an initial public offering, would be a default
unless the lenders consented. In addition, following an initial public
offering, PG&E Corporation would be required to reduce the amount of its term
loans to an aggregate of $500 million. Neither we nor PG&E Corporation require
approval of lenders to transfer to third parties all or a portion of the equity
of a number of lower level subsidiaries, including those holding our advanced
development projects, so long as we retain the proceeds as cash, use the
proceeds to pay down debt or reinvest the proceeds in our business.
Possibilities for raising additional equity include an initial public offering,
a private placement of our common and/or preferred equity, the sale of a
minority interest in a subsidiary holding our integrated energy and marketing
business segment, and the issuance of equity in an entity that would be formed
to hold a selected group of generating projects, primarily including projects
currently in advanced development.
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Our integrated power generation and energy marketing and trading business is
principally engaged in the following areas:
. ownership and operation of generating facilities;
. greenfield development and construction;
. contractual control of generating capacity;
. energy marketing and trading; and
. risk management.
Ownership and Operation of Generating Facilities
As of June 30, 2001, we had ownership or leasehold interests in 23 operating
generating facilities with a net generating capacity of 6,438 MW. These
facilities consist of nine gas-fired generating facilities with a net
generating capacity of 2,263 MW, 10 generating facilities that primarily burn
coal or waste coal, in some cases, in combination with oil or gas, with a net
generating capacity of 2,997 MW, three hydroelectric systems or pumped storage
facilities with a net generating capacity of 1,166 MW and one 12 MW wind
generating facility.
We provide operating and/or management services for 20 of our 23 owned and
leased generating facilities. Our plant operations are focused on maximizing
the availability of a facility to generate power during peak energy price
hours, improving operating efficiencies and minimizing operating costs. We
place a heavy emphasis on safety standards, environmental compliance and plant
flexibility. Our incentive structure is designed to align individual goals and
performance with our overall strategic objectives. As evidence of the success
of our operating strategy, we achieved over 90% availability at our generating
facilities during 2000. At the facilities we acquired in New England in 1998,
we have reduced non-fuel operating costs by almost 50% compared to the pre-
acquisition period of January 1997 through September 1998, reduced staffing by
approximately 35% from levels in place immediately prior to the acquisition and
achieved over 89% availability at our coal units.
Our plant operating philosophy emphasizes and encourages operational
autonomy of the individual plant employee to identify and resolve operational
issues specific to each generating facility. We actively develop an awareness
of market dynamics and operational information at all organizational levels to
enhance the effectiveness of our operational decision making. Similarly, our
uniform incentive structure aligns the performance of every employee with our
strategic goals. We also have an active, broadly utilized, best practices
program which we believe brings together the resources and information
necessary to achieve continuous improvement throughout our company. We use
independent consultants to critically assess our performance in various key
categories, and we use these assessments to continually improve our plant
operations.
We have a proven record of bringing leading-edge high efficiency generating
technology to the marketplace. For example, we have successfully developed high
efficiency combined-cycle generating facilities using both aero-derivative and
frame-type combustion turbines operating with unanticipated outage rates below
industry averages. We were also the first to successfully permit, construct and
operate a domestic coal-fired generating facility using selective catalytic
reduction to reduce nitrogen oxide emissions.
We view safety and environmental stewardship as paramount to achieving
overall efficient and profitable operating performance. We have received more
than 20 local, state and national environmental awards, and we routinely
evaluate and reward our employees based, in part, on safety and environmental
performance factors.
Our generating facilities can be divided into two categories based on the
method of sale of their electric output. The first category is generating
facilities that sell their electrical output in the competitive wholesale
electric market on a spot basis or under contractual arrangements of various
terms. These generating facilities are generally referred to as "merchant
plants." The second category is generating facilities that sell all or a
62
majority of their electrical capacity and output to one or more third parties
under long-term power purchase agreements tied directly to the output of that
plant. These generating facilities are generally referred to as "independent
power projects."
All of the generating facilities we developed or placed in operation prior
to 1997 are independent power projects, while all those we acquired, placed in
operation or controlled through contract during or after 1997 are merchant
plants. Our generating facilities under construction or development are
generally expected to be operated as merchant plants.
Merchant Power Plants
We manage the sale of the electric output from our merchant plants through
integrated teams that include marketing, trading and plant operating personnel.
We have closely linked the personnel on our trading floor with those in our
generating facilities' control rooms through the electronic sharing of both
market and operating data. This real-time exchange of market and operating
information allows us to make better informed decisions to vary the output of
and fuel used in our generating facilities in response to constantly changing
regional power prices. We coordinate our maintenance decisions to balance
maintenance costs against lost profit opportunity from downtime, seeking to
carry out our maintenance in periods of low power prices. We generally do not
sell the output of a specific merchant plant to a specific customer but rather
combine the output of our merchant plants with market purchases of electricity
to increase the reliability of, and provide our customers with, tailored power
products.
Our merchant plants can be divided into either baseload or
peaking/intermediate facilities. Baseload facilities generally have low
variable costs and are economic to operate most hours of the year. They
typically operate during nights and weekends, although sometimes at reduced
output levels. We generally consider a baseload facility to be any fossil-
fueled facility with an annual average capacity factor in excess of 60% or any
hydroelectric facility with limited water storage capability. Annual capacity
factor means the percentage of maximum potential generation that was actually
generated by a given facility. Peaking/intermediate facilities generally have
higher variable costs and operate primarily during the higher energy price
hours of the year. We generally consider a peaking/intermediate facility to be
any fossil-fueled facility with an annual average capacity factor below 60%,
any hydroelectric pump storage facility and any conventional hydroelectric
facility with substantial seasonal water storage capability.
Independent Power Projects
We hold our interests in independent power projects through wholly owned
subsidiaries. We had a net ownership interest of 1,278 MW in independent power
projects as of June 30, 2001. Typically, we manage and operate these facilities
through an operation and maintenance agreement and/or a management services
agreement. These agreements generally provide for management, operations,
maintenance and administration for day-to-day activities, including financial
management, billing, accounting, public relations, contracts, reporting and
budgets. In order to provide fuel for our independent power projects, natural
gas and coal supply commitments are typically purchased from third parties
under long-term supply agreements.
The revenues generated from long-term power sales agreements by our
independent power projects usually consist of two components: energy payments
and capacity payments. Energy payments are typically based on the project's
actual electrical output and capacity payments are based on the project's total
available capacity. Energy payments are made for each kilowatt-hour of energy
delivered, while capacity payments, under most circumstances, are made whether
or not any electricity is delivered. However, capacity payments may be reduced
if the facility does not attain an agreed availability level.
Greenfield Development and Construction
We are actively engaged in the development and construction of power
generating facilities. Since 1991, we have placed 21 generating facilities in
construction with a net generating capacity of 9,037 MW.
63
Historically, we have focused principally on the development and
construction of natural gas-fired and coal-fired generating facilities. We also
have developed facilities that utilize other power generating technologies,
including wind. We have significant expertise in a variety of power generating
technologies. We also have substantial capabilities in each aspect of the
development and construction process, including site selection, design,
engineering, procurement, construction management, permitting, garnering local
community support, resolving environmental issues, fuel and resource
acquisition, management, financing and operations.
We currently own or have committed to lease or acquire seven generating
facilities under construction in six states that will have a net generating
capacity of 5,480 MW. These projects are expected to be placed in service in
2002 and 2003. We consider a generating facility to be under construction once
we or the lessor has acquired the necessary permits to begin construction,
broken ground at the project site and contracted to purchase the major
machinery for the project, including the combustion turbines. In addition, we
have six generating facilities in advanced development that are expected to
have a net generating capacity of 6,234 MW. We consider a generating facility
to be in advanced development when we have contractual commitments or options
to purchase the turbines necessary to complete the project, have control of the
site and have initiated all necessary permitting. We also have options to
acquire an additional 7,795 MW of turbines and a site inventory of early stage
developments for these turbines.
Our greenfield development efforts focus on securing control of sites that
are strategically positioned in attractive competitive regional markets. We are
concentrating our development efforts in regions where we do not currently have
a substantial operating presence in order to increase our regional diversity.
In the early stage of development, we secure additional sites based on a goal
of having at least two potential sites moving through the development process
for each future project. We believe these additional sites will give us the
flexibility to capitalize on the evolving regulatory and market conditions in
these new regional markets.
We develop new generating facilities through a disciplined process governed
by regional and local market conditions, including:
. regional demand conditions and growth rate;
. the rate at which new generating capacity is being constructed by
competitors;
. the pricing and availability of fuel at the site and in the regional
market;
. local community support for the development;
. regulatory status and market structure;
. the number, size, experience, market penetration and financial resources
of competitors and wholesale customers in the market; and
. electric and gas transmission conditions and constraints in the market.
As part of our development process, we have expertise in forecasting longer-
term regional trends and in-depth knowledge of the current electric and fuel
markets derived from our marketing and trading operations. We believe the
combination of these long-term and short-term views give us a competitive
advantage in selecting regions and specific sites for greenfield development.
We have secured contractual commitments and options for 60 new combustion
turbines for our large, gas-fired facilities, representing 20,218 MW of net
generating capacity. Nineteen of these turbines, representing approximately
6,189 MW, are for generating facilities under construction or recently placed
in operation as of August 15, 2001. These combustion turbines will be used
primarily in combined cycle configurations. We have diversified the source of
our turbine commitments and options in order to secure bargaining leverage with
suppliers, capitalize on rapidly changing turbine technology and match
different turbine characteristics to different regional markets.
Most of our turbine commitments use the latest generation of combustion
technology, which is commonly known as G technology. These G technology
turbines are designed to result in higher capacity utilization, lower
64
cost output and a 3% to 5% higher combustion efficiency than the F technology
turbines generally being deployed in most new generating facilities in North
America. We also have secured 23 FB turbines from General Electric. These
turbines are expected to be slightly less efficient than G technology turbines,
but are designed to have 1% to 2% higher combustion efficiency than the more
standard F technology turbines. In light of our deployment of advanced
technology, we have also arranged with each of our turbine vendors for long-
term service agreements covering all 60 turbines. These agreements have
predetermined pricing, and cover the schedule for major overhauls, parts and
associated labor, for at least ten years.
Two of the suppliers of G technology turbines have encountered problems in
their initial commercial installations of these turbines. Our Lake Road and La
Paloma facilities are being constructed by Alstom Power, Inc. Alstom has
advised us that it may take up to three years to develop and implement
modifications to its G technology turbines that are necessary to achieve the
guaranteed level of efficiency and output. We expect that the Lake Road and La
Paloma facilities will begin commercial operations at reduced performance and
output levels because of the technology issues with Alstom's G technology
turbines. We also encountered start-up problems with the Siemens Westinghouse G
technology installed in our Millennium facility. These problems delayed the
expected date of commercial operations for this facility which began commercial
operations in April 2001. We do not expect that the start-up problems with the
Siemens Westinghouse G technology turbine installed at the Millennium facility
will result in a reduction of performance below guaranteed levels of efficiency
or output. The construction contracts for each of the Millennium, Lake Road and
La Paloma projects provide for liquidated damages that we believe could
significantly, but not fully, offset the financial impact associated with the
delays of these turbines in achieving their expected level of performance.
The following table describes the large scale turbines that we have secured
through contractual commitments or options.
Estimated
Quantity Generating
of Capacity(1)
Manufacturer and Type Turbines (MW)
--------------------- -------- -----------
G Technology Turbines
Mitsubishi 501G Turbine............................... 21 8,322
Siemens Westinghouse 501G Turbine..................... 7 2,532
Alstom GT24 Turbine................................... 7 1,961
F Technology Turbines...................................
General Electric 7FB Turbine.......................... 23 6,877
General Electric 7FA Turbine.......................... 2 526
--- ------
Total............................................... 60 20,218
=== ======
- --------
(1) Approximate baseload and peaking/intermediate capacity based on anticipated
configuration of the turbine.
Contractual Control of Generating Capacity
We are increasing our generating capacity through contractual control of the
electric output of generating facilities in strategic markets. These
contractual arrangements will allow us to increase our generating capacity with
less capital than if we only developed and acquired generating facilities. We
have executed various long-term contracts representing 4,031 MW of generating
capacity, which result in control of 518 MW of operating generating capacity
and 3,513 MW of generating capacity in construction or development as of June
30, 2001. These contracts include control of all or a portion of the output of
17 smaller generating facilities through arrangements with NEP. In return for
our assumption of the purchase obligations under these agreements, NEP has
agreed to pay an average of $111 million per year through January 2008 to
offset our payment obligations under these contracts. We anticipate the
opportunity to increase our controlled generating capacity beyond 4,031 MW and
will do so if warranted.
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Our energy marketing, trading, development, financing and operational skills
have allowed us to successfully identify and capitalize on opportunities to
increase our controlled generating capacity without direct asset ownership.
These skills include market assessment, transaction screening, pricing and
valuation, long-term contract negotiation, risk management and project
implementation. We believe that these skills will allow us to continue to
increase our contractually controlled generating capacity.
Our primary method of achieving contractual control of generating capacity
is through tolling agreements. Tolling agreements establish a contractual
relationship that grants us the right to use a third party's generating
facility to convert our fuel, typically natural gas, to electricity. We have
the right to decide the timing and amount of electricity production within
agreed operating parameters. The owner of the facility receives a fixed
capacity payment for the committed availability of its facility and a variable
payment for production costs. The fixed payment is subject to reduction if the
owner fails to meet specified targets for facility availability and other
operating factors.
The terms of the five tolling agreements we had entered into as of June 30,
2001 range from 10 to 25 years commencing on the date of initial commercial
operations of the generating facility. Most of the generating facilities are
under construction or in development with commercial operations expected to
commence between 2001 and 2004. These tolling agreements provide us with
control of gas-fired plants in the Mid-Atlantic, Midwestern, Southern and
Western regions of the United States.
Energy Marketing and Trading
We engage in the energy marketing and trading of electric energy, capacity
and ancillary services, fuel and fuel services such as transport and storage,
emission credits and other related products through over-the-counter and
futures markets across North America. Our energy marketing and trading team
manages the supply of fuel for, and the sale of electric output from, our owned
and controlled generating facilities and other trading positions. During the
year ended December 31, 2000, we sold approximately 283 million MW hours of
power and an average of 6.5 billion cubic feet of natural gas per day. We
market and trade all types of fuels necessary for our owned and controlled
generating facilities, including natural gas, coal and oil. We believe that the
diversity of products and markets in which we trade allows us to remain
profitable under varying market conditions.
We use financial instruments such as futures, options, swaps, exchange for
physical, or EFPs, contracts for differences, or CFDs (for example,
transmission congestion credits or natural gas basis) and other derivatives to
provide flexible pricing to our customers and suppliers and manage our purchase
and sale commitments, including those related to our owned and controlled
generating facilities, gas pipelines and storage facilities. We also use
derivative financial instruments to reduce our exposure relative to the
volatility of market prices. Financial instruments are also used to hedge
interest rate and currency volatility. Combining physical and financial
instruments allows us to prudently manage asset value, trading value, debt
expense and currency value.
We also evaluate and implement highly structured long-term and short-term
transactions. These transactions include management of third party energy
assets, short-term tolling arrangements, management of the requirements of
aggregated customer load through full requirement contracts, restructured
independent power project contracts and purchase and sale of transportation,
storage and transmission rights through auctions and over-the-counter markets.
We believe these transactions provide us with a more stable earnings stream, a
method of managing our longer-term risks and additional portfolio growth and
flexibility.
Our energy marketing and trading operations provide the following products
and services for our integrated portfolio of assets and our growing customer
base.
Electricity Marketing and Trading
We aggregate electricity and related products from our owned and controlled
generating facilities and from other generators and marketers. We then package
and sell such electricity and related products to electric
66
utilities, municipalities, cooperatives, large industrial companies,
aggregators and other marketing and retail entities. We also buy, sell and
transport power to and from third parties under a variety of short-term
contracts. We manage all of our power positions, whether from our owned and
controlled generating facilities or from other contracts, as an integrated
power portfolio. We believe that our energy marketing and trading capabilities
allow our integrated portfolio of generating facilities to capitalize on
opportunities across regions, time frames and commodity types. In addition to
executing transactions through brokers, futures markets and over-the-counter
markets, we focus on customer business that leverages our integrated asset and
trading skills.
Natural Gas Marketing and Trading
We purchase natural gas from a variety of suppliers under daily, monthly,
seasonal and long-term contracts with pricing, delivery and volume schedules to
accommodate the requirements of our owned and controlled generating facilities
and various transactions. We also buy, sell and arrange transportation to and
from third parties under a variety of short-term agreements. Our natural gas
marketing activities include contracting to buy natural gas from suppliers at
various points of receipt, arranging transportation, negotiating the sale of
natural gas and matching natural gas receipt and delivery points to the
customer based on geographic logistics and delivery costs. In 2000, we
refocused our natural gas trading activities towards transactions more closely
related to our integrated strategy. We sold an average of 6.5 billion cubic
feet per day of natural gas in 2000, down from 8.4 billion cubic feet in 1999.
We arrange for transportation of natural gas on interstate and intrastate
pipelines through a variety of means, including short-term and long-term firm
and interruptible agreements. We also enter into various short-term and long-
term firm and interruptible agreements for natural gas storage in order to
offer peak delivery services to satisfy winter heating and summer electric
generating demands. These services are designed to provide an additional level
of performance security and flexibility to our generating facilities and
customers.
Coal, Oil and Emissions Marketing and Trading
We buy, secure transportation for and manage the sulfur content of the coal
and oil requirements of our owned and controlled generating facilities. We also
purchase and sell coal, oil and emissions credits from and to third parties. We
are active in the NYMEX look-alike and Powder River Basin coal markets, and are
actively participating in the development of the eastern United States "Rail"
and South American coal markets. Our participation in the merchant coal, oil
and emissions markets has enabled us to execute complex transactions which
leverage our cross-commodity capabilities. For example, we have entered into an
agreement to sell coal and oil bundled with emission credits.
Load Management or Full Requirements Arrangements
Deregulation of the energy industry has provided many consumers with the
ability to seek and receive customized energy services. Consumers are
particularly interested in purchasing volumes of fuel and electricity that
closely match their specific needs. In order to satisfy this consumer demand,
an increasing number of companies aggregate blocks of customers, buy power at
wholesale and deliver it to end-user consumers. These aggregation services are
especially critical because electricity is a commodity that cannot be stored in
large quantities and therefore the electricity must be generated at the same
time as it is needed for consumption. As part of our integrated generation,
energy marketing and trading business, we enter into contracts to supply
natural gas and electricity, known as load management or full requirements
supply, to these load aggregator companies in the exact amount and quality
purchased by their end-user customers. We believe that these load management or
full requirements arrangements enhance our financial returns and provide
earnings stability to our portfolio. Our load management experience includes
several five to ten year transactions to provide full-requirements default
service, to replace energy from third party independent power projects and to
supply an aggregator's energy requirements.
Our largest load management contracts are the wholesale standard offer
service agreements with affiliates of NEP, from whom we purchased 4,800 MW of
owned and controlled generating capacity in 1998. Under the
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wholesale standard offer service agreements, we supply a fixed percentage of
the full requirements of the retail customers of NEP's affiliates who receive
standard offer service in Massachusetts and Rhode Island. These retail
customers may select alternative suppliers at any time. We receive a fixed
floor price for the electricity we provide under the wholesale standard offer
service agreements. Standard offer service is intended to stimulate the retail
electric markets in these states by gradually increasing the fixed price of
electricity under this service. The fixed price increases periodically by
specified amounts and also increases if the prices of natural gas and fuel oil
exceed a specified threshold. Our sales volumes and revenues under the
wholesale standard offer service agreements totaled 17 million MW hours and
$587 million in 1999 and 13 million MW hours and $563 million in 2000. The
wholesale standard offer service agreement for Massachusetts terminates on
December 31, 2004 and the wholesale standard offer service agreement for Rhode
Island terminates on December 31, 2009.
Fuel Supply, Transport and Electric Transmission Management
We enter into contracts for fuel supply, fuel transportation and electric
transmission primarily to meet the needs of our owned and controlled generating
facilities and to capitalize on other trading opportunities. We believe that
access to long-term fuel supply, fuel transportation and electric transmission
allows us to better respond to market cycles and one-time events. As such, we
seek to maintain a variety of relationships with large producers and
transporters with whom we enter into select long-term commitments. We also
enter into shorter term arrangements on an opportunistic basis. We also have a
15-year agreement to charter the Energy Enterprise, a U.S. flag ocean going
self-unloading vessel, to transport both domestic and foreign coal to our
generating facilities.
Risk Management Controls
We manage the risk associated with our energy marketing and trading
operations through a comprehensive set of policies and procedures involving
senior levels of our management. Our risk management committee sets value-at-
risk limitations and regularly reviews our risk management policies and
procedures. Trading is permitted only in accordance with these procedures, as
well as with policies set forth by the corporate risk policy committee of PG&E
Corporation. Within this framework, our risk management committee oversees all
of our energy marketing and trading activities.
Most of our risk management models are reviewed by third party experts with
extensive experience in specific derivative applications. We believe that the
combination of our risk management committee's direct involvement and our
highly qualified quantitative team results in disciplined management of our
energy investments and contracts and their associated commodity price and
volume risk.
Our risk management committee is headed by an independent risk management
officer. Our risk management group is structured as a separate unit in our
organization. We believe this separate organizational structure enhances our
ability to ensure the implementation and management of our risk management
policies. Our risk management group is comprised of a team of experienced risk
management professionals.
Our risk management group is responsible for the day-to-day enforcement of
the policies, procedures and limits of our energy marketing and trading
activities and evaluating the risks inherent in proposed transactions. These
key activities include evaluating and monitoring the creditworthiness of our
trading counterparties, setting and monitoring volumetric and loss limits on
our portfolio risks, establishing and monitoring trading limits on products, as
well as on individual traders, validating trading transactions and performing
daily portfolio valuation reporting, including mark-to-market valuation. Our
risk management policies are implemented across all of our trading transactions
through our sophisticated risk management software systems.
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Description of our Generating Facilities
The following table provides information regarding each of our owned or
controlled operating generating facilities, as well as those under construction
or in advanced development as of August 15, 2001:
Our Net Date of
Total Interest in Primary Output Commercial
Generating Facility State MW(1) Total MW(2) Structure Fuel Sales Method Status Operation
- ------------------- ------- ------ ----------- ---------- --------------- ------------------------- ------------ ----------
New England Region
Brayton Point
Station......... MA 1,599 1,599 Owned Coal/Oil Competitive Market Operational 1963-1974
Salem Harbor
Station......... MA 745 745 Owned Coal/Oil Competitive Market Operational 1952-1972
Bear Swamp
Facility........ MA 599 599 Leased Water Competitive Market Operational 1974
Manchester St
Station......... RI 495 495 Owned Natural Gas Competitive Market Operational 1995
Connecticut River
System.......... NH/VT 484 484 Owned Water Competitive Market Operational 1909-1957
Masspower........ MA 267 35 Owned Natural Gas Power Purchase Agreements Operational 1993
Pittsfield(3).... MA 173 143 Leased Natural Gas Power Purchase Agreements Operational 1990
and Competitive Market
Milford
Power(3)........ MA 171 96 Contract Natural Gas Competitive Market Operational 1994
Deerfield River
System.......... MA/VT 83 83 Owned Water Competitive Market Operational 1912-1927
Pawtucket
Power(3)........ RI 69 69 Contract Natural Gas Competitive Market Operational 1991
14 smaller
facilities(3)... Various 193 193 Contract Renewable/Waste Competitive Market Operational Various
Millennium....... MA 360 360 Owned Natural Gas Competitive Market Operational 2001
Lake Road........ CT 840 840 Leased Natural Gas Competitive Market Construction 2001
------ ------
Subtotal........ 6,078 5,741
------ ------
Mid-Atlantic and
New York Region
Power Purchase Agreements
Selkirk.......... NY 345 145 Owned Natural Gas and Competitive Market Operational 1992
Carneys Point.... NJ 269 135 Owned Coal Power Purchase Agreements Operational 1994
Logan............ NJ 225 113 Owned Coal Power Purchase Agreement Operational 1994
Northampton...... PA 110 55 Owned Waste Coal Power Purchase Agreements Operational 1995
Panther Creek.... PA 80 40 Owned Waste Coal Power Purchase Agreement Operational 1992
Scrubgrass....... PA 87 44 Owned Waste Coal Power Purchase Agreement Operational 1993
Madison.......... NY 12 12 Owned Wind Competitive Market Operational 2000
Liberty
Electric........ PA 568 568 Contract Natural Gas Competitive Market Construction 2002
Athens........... NY 1,080 1,080 Owned Natural Gas Competitive Market Construction 2003
Mantua Creek..... NJ 897 897 Owned Natural Gas Competitive Market Development 2003
Liberty
Generating...... NJ 1,203 1,203 Owned Natural Gas Competitive Market Development 2004
------ ------
Subtotal........ 4,876 4,292
------ ------
Midwest Region
Georgetown....... IN 240 160 Contract Natural Gas Competitive Market Operational 2000
Ohio Peakers..... OH 144 144 Owned Natural Gas Competitive Market Operational 2001
Covert........... MI 1,170 1,170 Owned Natural Gas Competitive Market Construction 2003
Badger........... WI 1,170 1,170 Owned Natural Gas Competitive Market Development 2003
Goose Lake....... IL 1,170 1,170 Owned Natural Gas Competitive Market Development 2004
Unannounced
toll............ 1,075 1,075 Contract Natural Gas Competitive Market Development 2004
------ ------
Subtotal........ 4,969 4,889
------ ------
Southern Region
Indiantown....... FL 360 126 Owned Coal Power Purchase Agreement Operational 1995
Cedar Bay........ FL 269 135 Owned Coal Power Purchase Agreement Operational 1994
Attala........... MS 526 526 Owned Natural Gas Competitive Market Operational 2001
Southaven........ MS 810 810 Contract Natural Gas Competitive Market Construction 2003
Caledonia........ MS 810 810 Contract Natural Gas Competitive Market Construction 2003
------ ------
Subtotal........ 2,775 2,407
------ ------
Western Region
Spencer.......... TX 178 178 Owned Natural Gas Power Purchase Agreement Operational 1955-1972
Hermiston........ OR 474 237 Owned Natural Gas Power Purchase Agreement Operational 1996
Colstrip......... MT 40 5 Owned Waste Coal Power Purchase Agreement Operational 1990
Mountain View.... CA 66 66 Owned(4) Wind Competitive Market Construction 2001
La Paloma........ CA 1,121 1,121 Leased Natural Gas Competitive Market Construction 2002
Plains End....... CO 111 111 Owned Natural Gas Competitive Market Construction 2002
Harquahala....... AZ 1,092 1,092 Leased Natural Gas Competitive Market Construction 2003
Otay Mesa........ CA 500 250 Contract(5) Natural Gas Competitive Market Development 2003
Umatilla......... OR 598 598 Owned Natural Gas Competitive Market Development 2004
Meadow Valley.... NV 1,196 1,196 Owned Natural Gas Competitive Market Development 2004
------ ------
Subtotal........ 5,376 4,854
------ ------
Total........... 24,074 22,183
====== ======
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- --------
(1) Megawatts for our owned facilities are based on nominal MW, defined as
typical new and clean output at 59 degrees Fahrenheit at sea level.
Megawatts for contract-based output are based on the quantities stated in
the contracts.
(2) Our net interest in the total MW of an independent power project is
determined by multiplying our percentage of the project's expected cash
flow by the project's total MW. Accordingly, the net interest in total MW
does not necessarily correspond to our current percentage ownership or
leasehold interest in the project affiliate.
(3) We control all or a portion of the output of these 14 smaller generating
facilities, together with the Milford Power Project, the Pawtucket Power
Project and the Pittsfield Project, under long-term power purchase
agreements. In return for our assumption of the purchase obligations under
these agreements from NEP, NEP has agreed to pay an average of $111 million
per year through January 2008 to offset our payment obligations under these
contracts. The power purchase agreements terminate between 2009 and 2029.
(4) We have executed a contract to purchase the Mountain View facility when
construction is completed. The purchase has not yet closed.
(5) On July 10, 2001, we sold the Otay Mesa facility and retained control of up
to 250 MW of its generating capacity through a 10-year tolling arrangement.
Total MW shown for generating facilities under development are estimates
based on ratings of the turbines and other equipment to be installed at the
facility that reflects standardized site conditions. Once construction has
commenced on a generating facility, we can estimate the generating capacity of
the facility with more accuracy based on the actual configuration and site
conditions. Our net interest in an independent power project is determined by
multiplying our percentage of the project's expected cash flow by the project's
total MW.
In July 1999, ET-Power entered into a tolling agreement with SRW
Cogeneration Limited Partnership (SRW), which provided ET-Power with the right
to utilize up to 250 MWs at SRW's generating facility. In January 2001, SRW
attempted to terminate this tolling agreement, which ET-Power disputed. The
matter is now pending in arbitration.
The following section describes each of our owned generating facilities in
excess of 250 MW, as well as those under construction or announced projects in
advanced development that we expect to own and that will produce in excess of
250 MW.
New England Region Generating Facilities
Operating Facilities
Brayton Point Station. We own a 100% interest in Brayton Point Station, the
largest fossil-fired generating facility in New England with an aggregate
generating capacity of 1,599 MW. This facility, located in Somerset,
Massachusetts, on a 225-acre waterfront site, has three units of 255 MW, 255 MW
and 633 MW which are fueled primarily by coal, one unit of 446 MW which burns
either natural gas or heavy fuel oil depending on relative cost and
availability, and also includes 10 MW of on-site diesel generators. The first
unit at this facility commenced commercial operations in 1963, with all units
in operation by 1974. Brayton Point Station sells all of its electrical output
in the competitive market.
Deliveries of coal and fuel oil are currently made at a deep water port
located at this facility. We have secured a portion of the shipping
requirements for coal to this facility through the long-term charter of a
self-unloading vessel capable of delivering 75% of the normal annual coal
requirements of this facility and our Salem Harbor facility. In 1991, Brayton
Point was connected to a high-pressure natural gas transmission system and all
existing units have some gas firing capability. There is approximately 1.3
million barrels of fuel oil storage capacity in five tanks at this facility.
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Salem Harbor Station. We own a 100% interest in the Salem Harbor Station, a
745 MW fossil-fired generating facility located on a 65-acre waterfront site in
Salem, Massachusetts. Salem Harbor Station, which commenced commercial
operations in 1952, consists of three units of 84 MW, 80 MW and 150 MW that are
capable of burning coal, oil or a combination of the two, and one unit of 432
MW which burns only fuel oil. Deliveries of coal and fuel oil are currently
made at a deep waterport located at this facility. Salem Harbor Station sells
all of its electrical output in the competitive market.
Bear Swamp. We hold a 48-year lease, with renewal options, on the Bear Swamp
Facility, which consists of Bear Swamp Pumped Storage Station, a 589 MW fully
automated pumped storage facility, and Fife Brook Station, a 10 MW conventional
hydroelectric facility. This facility commenced commercial operations in 1974
and has an aggregate generating capacity of 599 MW. It occupies approximately
1,300 acres on the Deerfield River located in the towns of Rowe and Florida,
Massachusetts. The Bear Swamp facility sells all of its electrical output in
the competitive market.
The Bear Swamp Pump Storage Station operates by pumping water up to a
holding pond 770 feet above the Deerfield River when electricity is relatively
low priced and releasing this water to generate electricity when prices are
relatively high. It has a storage capacity equal to five hours of generation at
full capacity and typically generates power during weekdays and pumps and
stores water during weekends and nights. We believe the flexibility of this
facility complements our baseload facilities in the region and allows us to
more efficiently supply higher value energy products such as full requirements
supply.
Manchester Street Station. We own 100% of Manchester Street Station, a 495
MW combined-cycle gas-fired facility located in Providence, Rhode Island.
Previously a coal, oil and gas steam facility, Manchester Street Station was
completely repowered in 1995. This facility has three units that burn natural
gas as their primary fuel and is capable of firing oil as an emergency back-up
fuel to natural gas. Manchester Street Station sells all of its electrical
output in the competitive market.
Connecticut River System. We own 100% of the Connecticut River System, a
conventional hydroelectric system located along the Connecticut River in New
Hampshire and Vermont. The Connecticut River System consists of six stations
with 26 generating units that are capable of producing an aggregate generating
capacity of 484 MW. Through its series of reservoirs, dams and powerhouses,
this system manages the flow of approximately 300 miles of the Connecticut
River. Two of the six stations operate mainly during peak periods in order to
respond quickly to high prices for electricity. The Connecticut River System
sells all of its electrical output in the competitive market.
Masspower. We own a 13.2% interest in Masspower, a 267 MW gas-fired combined
cycle cogeneration facility located in Springfield, Massachusetts. Our net
equity interest in this facility's aggregate generating capacity is
approximately 35 MW. This facility, which commenced commercial operations in
1993, consists of two gas turbine generators, each feeding exhaust gases to a
heat recovery steam generator. Steam from the two heat recovery steam
generators is fed to a steam turbine for generating additional electricity.
Masspower primarily sells its electrical capacity and output to Boston
Edison Company, Commonwealth Electric Co. and Massachusetts Municipal Wholesale
Electric Co. under separate power purchase agreements with initial terms of
either 15 or 20 years, the earliest of which expires in 2008. Each of these
power purchase agreements provide for capacity and energy payments and have
fuel escalation clauses. Masspower sells the balance of its electrical capacity
and output into New England markets. Masspower also sells an annual average of
50,000 pounds of steam per hour to Solutia under a steam sales agreement with
an initial term of 20 years that expires in 2013.
Millennium. We own 100% of the Millennium Power Project, a 360 MW natural
gas-fired combined-cycle generating facility located in Charlton,
Massachusetts. It began commercial operations in April 2001.
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Millennium was constructed by Bechtel Power Corporation. This facility
incorporates the second installation from Siemens Westinghouse Power
Corporation's 501G combustion turbine line and the first to be developed in a
combined-cycle configuration. It is intended to operate on both natural gas and
fuel oil. Millennium is anticipated to sell all of its electrical output in the
competitive market.
Millennium had start-up problems that delayed commercial operation. In
addition, it has not yet been tested using fuel oil. We have reached a
settlement with Bechtel and Siemens under which we will operate the facility
during the summer of 2001 and will permit Bechtel and Siemens to make further
modifications and test using fuel oil during the fall. We do not expect that
these problems will result in a reduction of performance below guaranteed
levels of efficiency and output.
NEP Power Purchase Agreements. We control the output of 17 smaller
generating facilities under long-term power purchase agreements. In return for
our assuming the obligations under these power purchase agreements, NEP has
agreed to pay an average of $111 million per year through January 2008 to
offset our payment obligations under these contracts.
The facilities we control in whole or in part through these power purchase
agreements include the 171 MW Milford Power Project, the 173 MW Pittsfield
Project, the 69 MW Pawtucket Power Project and 14 other small generating
facilities with a total generation capacity of 193 MW fueled by municipal
waste, water, landfill gas or wood. The power purchase agreements terminate
between 2005 and 2029.
Generating Facilities Under Construction
Lake Road. The Lake Road facility is an 840 MW natural gas-fired combined-
cycle plant located in Killingly, Connecticut that is under construction. This
facility is being constructed by Alstom under a fixed price construction
contract with a guaranteed date for commercial operations. This facility will
consist of three Alstom GT24 combustion turbines and is intended to be capable
of firing low sulfur distillate fuel oil as an alternative fuel source. Lake
Road is anticipated to sell all of its electrical output in the competitive
market.
Alstom has fallen behind its construction schedule on this facility and is
paying liquidated damages for such delay. Alstom is implementing a recovery
plan with a target commercial operations date in the first quarter of 2002. In
addition, we believe that Lake Road will not be able to operate on fuel oil
until after commercial operations can commence. The ability to operate on fuel
oil is contemplated in Lake Road's permit from the State of Connecticut and we
are keeping the State of Connecticut informed of progress on fuel oil firing
capability. As a result, we believe Alstom may be liable for further liquidated
damages.
Alstom is also experiencing performance issues with its GT24 turbines.
Alstom has advised us that the GT24 turbines should be operated at lower firing
temperatures until modifications can be made, which may take as long as three
years to implement fully. Operating the turbines at lower firing temperatures
will result in output and efficiency levels below the guaranteed levels
established in the contract with Alstom and, as a result, we may be able to
collect liquidated damages from Alstom. We expect that the Lake Road facility
will commence commercial operations at these reduced performance levels, which
are slightly less than the performance levels of the standard F technology
turbines.
Mid-Atlantic and New York Region Generating Facilities
Operating Facilities
Selkirk. We own an approximately 42% interest in the Selkirk Cogeneration
Facility, a 345 MW natural gas-fired combined-cycle cogeneration facility
located near Albany, New York. Our net equity interest in this facility's
aggregate generating capacity is approximately 145 MW. This facility commenced
commercial operations in 1992 and is capable of producing a maximum average
steam output of 400,000 pounds per hour.
72
Selkirk sells up to 265 MW of its electric capacity and output to
Consolidated Edison under a power purchase agreement with an initial term of 20
years that expires in 2014 and is renewable for another ten years at
Consolidated Edison's option. Selkirk also sells 80 MW of its electric capacity
and output to Niagara Mohawk Power under an amended and restated power purchase
agreement with a term of 20 years that expires in 2008. Under this agreement,
Niagara has contracted for approximately 48 MW of Selkirk's electric capacity
and the remaining 32 MW of electric capacity is available to be sold in the
competitive market. Selkirk is capable of producing over 400 MW in winter
conditions. Selkirk expects to be able to sell this excess electric capacity
and output, subject to further negotiations with Niagara and Consolidated
Edison.
Selkirk also sells up to 400,000 pounds per hour of steam to General
Electric under a steam sale agreement with an initial term of 20 years that
expires in 2014. Under this agreement, General Electric must purchase and use
the minimum amount of steam required to maintain Selkirk's status as a QF under
PURPA, which is currently 80,000 pounds per hour of steam. However, General
Electric's obligation to purchase and use steam is subject to reduction or
termination in the event its steam requirements are reduced or cease.
Carneys Point. We own a 50% interest in Carneys Point Generating Facility, a
269 MW pulverized coal cogeneration generating facility. Our net equity
interest in this facility's aggregate generating capacity is 135 MW. This
facility is located in Carneys Point, New Jersey and commenced commercial
operations in 1994.
Carneys Point sells up to 188 MW to Atlantic City Electric Company during
the summer and up to 173 MW during the winter under a power sale agreement with
an initial term of 30 years that expires in 2024. Under this agreement,
Atlantic City Electric Company must purchase a minimum of 637,700 MW per year
or pay for an equivalent amount of energy reduced by variable operating costs.
Carneys Point sells up to 650,000 pounds per hour of steam in the summer and
1,000,000 pounds per hour of steam in the winter to DuPont under a steam and
electricity purchase contract. This agreement has an initial term of 30 years
that expires in 2024. As long as DuPont has not closed down or abandoned its
manufacturing facility powered by Carneys Point, DuPont must take the minimum
amount of steam required for Carneys Point to maintain its status as a QF under
PURPA, which is currently approximately 60,000 pounds per hour. The price paid
by DuPont for steam under this agreement is adjusted for changes in Carneys
Point's average coal price.
Generating Facilities Under Construction
Athens. The Athens Generating project is an approximately 1,080 MW natural
gas-fired combined-cycle project that is currently under development in Athens,
New York. Athens will consist of three advanced Siemens-Westinghouse 501G
combustion turbine generators and associated systems and facilities. Bechtel
will construct the facility pursuant to a fixed price construction contract.
Bechtel was released to commence construction at the end of May 2001. This
project is expected to be the first new merchant power plant in the New York
Power Pool and will sell power into this power pool on a competitive basis.
Athens is expected to commence commercial operations in 2003.
Generating Facilities Under Development
Mantua Creek. The Mantua Creek Generating project is an approximately 897 MW
natural gas-fired combined-cycle project currently under development in West
Deptford, New Jersey. This project will consist of three GE 7FB advanced
combustion turbine generators and associated systems and facilities. Mantua
Creek will be our first owned merchant generating project in the Pennsylvania,
New Jersey and Maryland (PJM) market, and is expected to sell all of its output
on a competitive basis. Mantua Creek is expected to commence commercial
operations in late 2003.
Liberty Generating. The Liberty Generating project is an approximately 1,203
MW natural gas-fired combined-cycle project currently under development in
Linden, New Jersey. This project will consist of three Mitsubishi 501G
combustion turbine generators and associated systems and facilities. This
project is anticipated to sell all of its output in the PJM competitive
electric market. Liberty Generating is expected to commence commercial
operations in 2004.
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Midwest Region Generating Facilities
Generating Facilities Under Construction
Covert. Covert is an approximately 1,170 MW natural gas-fired combined-cycle
project currently under construction in Covert, Michigan. This project will
consist of three Mitsubishi 501G combustion turbine generators and associated
systems and facilities. This project is being constructed by the Shaw Group.
Covert is anticipated to sell all of its output in the competitive market.
Covert is expected to commence commercial operations in 2003.
Generating Facilities Under Development
Badger. Badger is an approximately 1,170 MW natural gas-fired combined-cycle
project currently under development in Pleasant Prairie, Wisconsin. This
project will consist of three Mitsubishi 501G combustion turbine generators and
associated systems and facilities and, along with Covert and Goose Lake, is
expected to be constructed by the Shaw Group. Badger is anticipated to sell all
of its output in the competitive market. Badger is expected to commence
commercial operations in 2003.
Goose Lake. Goose Lake is an approximately 1,170 MW natural gas-fired
combined-cycle project currently under development in Grundy County, Illinois.
This project will consist of three Mitsubishi 501G combustion turbine
generators and associated systems and facilities and, along with Covert and
Badger, is expected to be constructed by the Shaw Group. Goose Lake is
anticipated to sell all of its output in the competitive market. Goose Lake is
expected to commence commercial operations in 2004.
Southern Region Generating Facilities
Operating Facilities
Attala. The Attala Power Project is a 526 MW natural gas-fired combined-
cycle power plant in Attala County, Mississippi, that commenced commercial
operation in June 2001. We acquired Attala from Duke Energy North America in
September 2000. Attala consists of two General Electric 7FA combustion turbine
generators. This facility is anticipated to sell all of its electric output in
the competitive market. Attala is directly interconnected into the Entergy
wholesale market, which has both actively traded over-the-counter broker
markets and established New York Mercantile Exchange futures contracts.
Indiantown. We own a 35% interest in the Indiantown Cogeneration Facility, a
360 MW pulverized coal cogeneration facility located on an approximately 240-
acre site in Martin County, Florida. Our net equity interest in this facility's
aggregate generating capacity is approximately 126 MW. Indiantown, which
commenced commercial operations in 1995, utilizes pulverized coal technology
consisting of a single pulverized coal boiler, a steam turbine generator, air
pollution control equipment and a selective catalytic reduction system to
reduce nitrogen oxides.
Indiantown sells all of its capacity and electrical output to Florida Power
and Light Company under a power purchase agreement with an initial term of 30
years that expires in 2025. Indiantown also supplies up to 745 million pounds
of steam per year to a citrus processing plant owned by Caulkins Indiantown
Citrus Company (Caulkins) under an energy services agreement with an initial
term of 15 years. Under the energy services agreement, Caulkins must purchase
the lesser of 525 million pounds of steam per year or the minimum quantity of
steam per year necessary for Indiantown to maintain its status as a QF under
PURPA. The coal supplier to Indiantown, Lodestar, is currently in bankruptcy.
The price for coal under the Lodestar contract is below current spot market
levels.
Cedar Bay. We own an effective 50% interest in the Cedar Bay Generating
Facility, a 269 MW coal-fired cogeneration facility located in Jacksonville,
Florida. Our net equity interest in this facility's aggregate generating
capacity is 135 MW Cedar Bay, which commenced commercial operations in 1994,
consists of three circulating fluidized bed boilers, a steam turbine generator,
air pollution control equipment and a selective non-catalytic reduction to
reduce nitrogen oxides.
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Cedar Bay sells its electric capacity and output to Florida Power and Light
Company under a power purchase agreement with an initial term of 19 years that
expires in 2013. Cedar Bay also sells up to 215,000 pounds per hour of steam to
Smurfit Stone Container Corporation under an energy services agreement with an
initial term of 19 years that expires in 2013. Under this agreement, Smurfit
Stone Container Corporation pays Cedar Bay a capacity payment according to a
fixed schedule and a variable payment based on Cedar Bay's cost of coal. The
coal supplier to Cedar Bay, Lodestar, is currently in bankruptcy. The price for
coal under the Lodestar contract is below current spot market levels.
Western Region Generating Facilities
Operating Facilities
Hermiston. We own a 50% interest in the Hermiston Generating Facility, a 474
MW natural gas-fired cogeneration facility located in Hermiston, Oregon. Our
net equity interest in this facility's aggregate generating capacity is
approximately 237 MW. This facility, which commenced commercial operations in
1996, is a combined-cycle cogeneration facility that utilizes two GE 7FA
turbines and associated systems and facilities.
We sell our share of electric capacity and output generated by Hermiston to
PacifiCorp under a power sale agreement with an initial term that expires in
2016. PacifiCorp has an option to extend the term of this agreement for an
additional ten years. Hermiston also sells steam to a nearby food processing
facility owned by Lamb-Weston, Inc. under a retail energy services agreement
with a term of 20 years that expires in 2016.
Generating Facilities Under Construction
La Paloma. The La Paloma Generating Facility is an approximately 1,121 MW
natural gas-fired combined-cycle generating facility currently under
construction in western Kern County, California. This facility is being
constructed by Alstom under a fixed price construction contract. La Paloma will
consist of four Alstom GT24 combustion turbines and associated systems and
facilities. This facility will be our first gas-fired merchant power plant in
the California wholesale electric market.
Alstom has fallen behind its construction schedule on this facility. Alstom
has developed and is implementing a recovery plan with a target commercial
operations date in mid 2002, which is later than the schedule guaranteed in the
construction contract. Similar to our Lake Road facility, we expect that La
Paloma will enter into commercial operations at reduced performance and output
levels because of the technology issues with Alstom's GT24 turbines. Because of
the possible two to three year delay in achieving the guaranteed performance
levels, we may be able to collect liquidated damages from Alstom.
Harquahala. Harquahala is an approximately 1,092 MW natural gas-fired
combined-cycle generating project near Phoenix, Arizona. We commenced
construction in May 2001. Harquahala is being constructed by the Shaw Group.
This project will be a combined-cycle power facility using three Siemens
Westinghouse 501G advanced combustion turbine generators and will be equipped
with a zero liquid discharge system to minimize water consumption and the
creation of wastewater. Harquahala is expected to commence commercial
operations in 2003. The project is anticipated to sell all of its electrical
output into the competitive market.
Generating Facilities In Development
Otay Mesa. Otay Mesa is a 500 MW natural gas-fired combined-cycle facility
currently under development in San Diego County, California. This project is
scheduled to commence commercial operations in 2003. On July 10, 2001, we
completed the sale of this project. We retain the right to control up to 250 MW
of its generating capacity through a 10-year tolling arrangement, and expect to
sell the output under this tolling arrangement into the competitive market.
Umatilla. Umatilla is an approximately 598 MW natural gas-fired combined-
cycle project currently under development in Umatilla, Oregon. Umatilla will
consist of two General Electric 7 FB combustion
75
turbines and associated systems and facilities, and will be equipped with
state-of-the-art pollution control equipment. We are developing this project
adjacent to our existing 474 MW Hermiston facility in order to capture
operating efficiencies. This project will also be interconnected with our GTN
pipeline. Umatilla is anticipated to sell all of its electrical output into the
competitive market. Umatilla is expected to commence commercial operations in
2004.
Meadow Valley. Meadow Valley is an approximately 1,196 MW natural gas-fired
combined-cycle project currently under development near Maopa, Nevada. This
project will provide power for the southern Nevada energy market and will
complement our other facilities under development in the Western region. Meadow
Valley will consist of four General Electric 7 FB combustion turbine generators
and associated systems and facilities, and will be equipped with state-of-the-
art pollution control equipment to reduce its emissions. The project is
anticipated to sell all of its output in the competitive market. Meadow Valley
is expected to commence commercial operations in 2004.
Natural Gas Transmission Business
Our natural gas transmission business currently consists of our GTN
pipeline, a 5.2% interest in the Iroquois Gas Transmission System and our North
Baja pipeline under development. Our natural gas transportation business is
regulated by FERC.
The following table summarizes our gas transmission pipelines:
In Approx. 2000
Service Capacity Capacity Length Ownership
Pipeline Name Location Date (MMcf/d) Factor (miles) Interest
------------- ---------- ------- -------- -------- ------- ---------
GTN..................... ID, OR, WA 1961 2,700 96% 1,335 100.0%
Iroquois Gas
Transmission System.... NY, CT 1991 900 95% 375 5.2%
North Baja.............. AZ, CA 2002 500 N/A 77 100.0%
Gas Transmission Northwest
Our GTN pipeline consists of over 1,300 miles of natural gas transmission
mainline pipe with a capacity of 2.7 billion cubic feet of natural gas per day.
Our GTN pipeline begins at the British Columbia-Idaho border, extends through
northern Idaho, southeastern Washington and central Oregon, and ends on the
Oregon-California border, where it connects with other pipelines. This pipeline
is the largest transporter of Canadian natural gas into the United States.
During 2000, our GTN pipeline transported 967 billion cubic feet of natural
gas, a 5% growth in transported volumes from 1999. Since this pipeline
commenced commercial operations in 1961, it has experienced a five-fold
increase in peak system capacity. It also has a strong record of low cost,
efficient operation, including system reliability in 2000 in excess of 99% and
operating expenses that are among the lowest in the industry.
We believe our GTN pipeline is one of the most strategically located
pipeline assets in the Western United States for the following reasons:
. It is the only interstate pipeline directly linking the gas markets of
California and parts of the Pacific Northwest and the natural gas
supplies of the Western Canadian Sedimentary Basin and potentially the
natural gas rich North Slope of Alaska and Northwest Territories of
Canada.
. It transports about 30% of California's natural gas requirements and over
20% of the Pacific Northwest's natural gas requirements.
. The Western Canadian Sedimentary Basin is one of the largest and fastest
growing natural gas supply sources for North America. According to
Cambridge Energy Research Associates, the Western Canadian Sedimentary
Basin is capable of increasing its production for export by more than 30%
over the next five years to nearly 21 billion cubic feet per day. This
additional five billion cubic feet per day could supply about 50% of the
total United States market demand growth over the same period. The
Western Canadian Sedimentary Basin is expected to grow much faster than
producing basins in the United States leading to a growing market share
in the United States.
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. In 1981, GTN expanded to form a portion of the western leg of the Alaska
Natural Gas Transmission System, or ANGTS. If completed, ANGTS will
connect the natural gas reserves of the North Slope of Alaska and
Northwest Territories of Canada to the natural gas consuming markets of
Canada and the United States. We believe that ANGTS or an alternative
pipeline system could be completed within the next ten years.
. New gas-fired generating facilities in the California and Pacific
Northwest markets will require an additional 1.4 to 1.9 billion cubic
feet of natural gas per day by 2005, according to Cambridge Energy
Research Associates.
The mainline system of our GTN pipeline consists of two parallel pipelines
with 13 compressor stations totaling approximately 415,900 horsepower. GTN's
dual-pipeline system consists of approximately 639 miles of 36-inch mainline
pipe and approximately 590 miles of 42-inch mainline pipe. The original
pipeline commenced commercial operations in 1961 and was expanded throughout
the 1960's and in 1970, 1981, 1993, 1995 and 1998. The GTN pipeline includes
two laterals, the Coyote Springs Lateral, which supplies natural gas to
Portland General Electric Company, and the Medford Lateral, which supplies
natural gas to Avista Utilities and other entities. This pipeline interconnects
with facilities owned by Pacific Gas and Electric Company at the Oregon-
California border and with interstate pipelines in northern Oregon, eastern
Washington and southern Oregon. It also delivers gas along various mainline
delivery points to two local gas distribution companies.
Our GTN pipeline provides firm and interruptible transportation services to
third party shippers on a nondiscriminatory basis. Firm transportation services
means that the customer has the highest priority rights to ship a quantity of
gas between two points for the term of the applicable contract. During 2000,
96% of GTN's capacity was committed to firm transportation services agreements
with terms in excess of one year. The volume-weighted average remaining term of
these agreements is approximately 13 years. In addition, due to weather,
maintenance schedules and other conditions, additional firm capacity may become
available on a short-term basis. Interruptible transportation is offered when
short-term capacity is available. We also offer hub services, which allow
customers the ability to park or lend volumes of gas on our GTN pipeline.
Our GTN pipeline currently provides transportation services for over 65
customers. Our customers are local retail gas distribution utilities, electric
generators that utilize natural gas to generate electricity, natural gas
marketing companies that purchase and resell natural gas on a wholesale and
retail basis, natural gas producers and industrial companies. Our customers are
responsible for securing their own gas supplies and delivering them to our
pipeline system. We transport our customers' natural gas supplies either to
downstream pipelines and distribution companies or directly to points of
consumption.
There is a significant amount of greenfield development of gas-fired
generating facilities that will be directly connected to our GTN pipeline. Four
gas-fired power generating facilities currently under construction will obtain
their fuel requirements directly from GTN. During peak energy periods, these
generating facilities are expected to consume at least an additional 250
million cubic feet per day of natural gas transported on our GTN pipeline.
As a result of the full commitment of GTN's long-term capacity, the
significant increase in new gas-fired generating facilities and the rapid
growth in the natural gas consuming markets of California and the Pacific
Northwest, we plan to expand the capacity of our GTN pipeline by at least 500
million cubic feet of natural gas per day by the end of 2004. We expect the
first phase of this expansion, which will amount to approximately 220 million
cubic feet per day, to be completed by the end of 2002. In early 2001, we
executed binding precedent agreements for long-term firm transportation
contracts for approximately 200 million cubic feet of this planned capacity to
be fully operational in the third quarter of 2002. As a result of an open
season that we recently completed, we intend to complete a second phase of this
expansion for approximately 240 million cubic feet per day at a cost of
approximately $150 million, to be completed at the end of 2003. We have also
initiated development of a Washington lateral pipeline that will originate at
GTN mainline system near Spokane, Washington and extend approximately 260 miles
west toward western Washington.
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Iroquois Pipeline
We own a 5.2% interest in the Iroquois Gas Transmission System, an
interstate pipeline which extends 375 miles from the U.S.-Canadian border in
northern New York through the State of Connecticut to Long Island, New York.
This pipeline, which commenced operations in 1991, provides gas transportation
service to local gas distribution companies, electric utilities and electric
power generators, directly or indirectly through exchanges and interconnecting
pipelines, throughout the Northeast. The Iroquois pipeline is owned by a
partnership of seven U.S. and Canadian energy companies, including affiliates
of TransCanada Pipeline, Coastal Corporation, Dominion Resources and Keyspan
Energy. Iroquois has executed firm multi-year transportation services
agreements totaling 900 million cubic feet per day. This pipeline also provides
interruptible transportation services on an as available basis. Iroquois has
filed an application with FERC to expand its capacity by 220 million cubic feet
per day of natural gas and extend the pipeline into the Bronx borough of New
York City.
North Baja Pipeline
We have recently joined with Sempra Energy International and Mexico's
Proxima Gas, S.A. de C.V. to develop a 212-mile pipeline that will supply
natural gas to Northern Mexico and Southern California. This pipeline will
begin at an interconnection with El Paso Natural Gas Co. near Ehrenberg,
Arizona, traverse southeastern California and northern Baja California, Mexico
and terminate at an interconnection with the TGN Pipeline south of Tijuana. We
have filed an application with FERC for a certificate to build the 77-mile U.S.
segment of the project for a projected cost of $146 million. On May 18, 2001,
FERC issued a preliminary determination on non-environmental issues supporting
issuance of North Baja's requested authorization. Sempra Energy International
and Proxima Gas will direct development of the 135-mile Mexico segment. This
pipeline will have an expected initial capacity of 500 million cubic feet per
day.
We have signed agreements with five customers to transport up to 92% of the
initial projected daily capacity of 500 million cubic feet per day of natural
gas in 2002 and 2003, and 100% of the initial capacity in 2004 and beyond. The
weighted average term of these agreements is in excess of 20 years. We are
continuing discussions and negotiations with other potential customers and
working with Sempra Energy International on the potential for an expansion.
This pipeline is projected to be in partial service in the third quarter of
2002, and full service by the fourth quarter of 2002.
Competition
Power Generation Operations
As of August 15, 2001, we owned or leased 6,438 MW of electric generating
capacity and were constructing and developing an additional 11,714 MW of
electric generating capacity that serves, or will serve, wholesale energy
markets located in the United States. Competitive factors affecting the results
of operations of these generating facilities include new market entrants,
construction by others of more efficient generation assets and the number of
years and extent of operations in a particular energy market.
Other competitors operate power-generating projects in the regions where we
have invested in electric generation assets. Although local permitting and
siting issues often reduce the risk of a rapid growth in supply of generating
capacity in any particular region, projects are likely to be built over time
which will increase competition and lower the value of some of our generating
facilities.
There is also significant competition for the development and acquisition of
domestic unregulated power generating facilities. We compete against a number
of other participants in the non-utility power generation industry. Competitive
factors relevant to the non-utility power industry include financial resources,
credit quality, development expenses, market prices and conditions and
regulatory factors. Some of our competitors have greater financial resources
than we do and have a lower cost of capital.
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Energy Marketing and Trading Operations
Our energy marketing and trading operations compete with other energy
merchants based on the ability to aggregate supplies at competitive prices from
different sources and locations and to efficiently utilize transportation from
third-party pipelines and transmission from electric utilities. These
operations also compete against other energy marketers on the basis of their
relative financial position and access to credit sources. 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. As pricing information becomes increasingly
available in the energy marketing and trading business and as deregulation in
the electricity markets continues to evolve, we anticipate that our energy,
marketing and trading operations will experience greater competition and
downward pressure on per-unit profit margins.
Gas Transmission Operations
Our gas transmission business competes with other pipeline companies,
marketers and brokers, as well as producers who are able to sell natural gas
directly into the wholesale end-user markets, for transportation customers on
the basis of transportation rates, access to competitively priced gas supply
and growing markets and the quality and reliability of transportation services.
The competitiveness of a pipeline's transportation services to any market is
generally determined by the total delivered natural gas price from a particular
natural gas supply basin to the market served by the pipeline.
Our GTN pipeline accesses natural gas supplies from Western Canada and
serves markets in California and Nevada, and parts of the Pacific Northwest.
GTN competes with other pipelines with access to natural gas supplies in
Western Canada, the Rocky Mountains, the Southwest and British Columbia.
Our transportation volumes are also affected by the availability and
economic attractiveness of other energy sources. Hydroelectric generation, for
example, may increase with ample snowfall and displace demand for natural gas
as a fuel for electric generation. Finally, in providing interruptible and
short-term firm transportation service, we compete with released capacity
offered by shippers holding firm contracts for our capacity. The ability of our
gas transmission business to compete effectively is influenced by numerous
factors, including regulatory conditions and the supply of and demand for
pipeline and storage capacity.
Regulation
Various aspects of our business are subject to a complex set of energy,
environmental and other governmental laws and regulations at the federal, state
and local levels. This section summarizes some of the more significant laws and
regulations affecting our business at this time. It is not an exhaustive
description of all the laws and regulations which affect us. We cannot assure
you that, in the future, these laws and regulations will not change or be
implemented or applied in a way that we do not currently anticipate. The
discussion below includes certain forward-looking statements that reflect our
current estimates. These estimates are subject to periodic evaluation and
revision. Future estimates and actual results may differ materially from our
current expectations.
Electric and Gas Regulation
The Federal Energy Regulatory Commission, or FERC, is an independent agency
within the United States Department of Energy, or DOE. Under the Federal Power
Act, FERC regulates wholesale electricity sales and transmission of electricity
in interstate commerce. FERC is also responsible for licensing and inspecting
private, municipal and state-owned hydroelectric projects located on navigable
waterways and federal lands. Furthermore, under the Natural Gas Act, FERC has
jurisdiction over our natural gas marketing and transmission businesses with
respect to certain matters relating to, among other things, rates, accounts and
records, facilities, services and gas deliveries. FERC also determines whether
a public utility qualifies for exempt wholesale generator, or EWG, status under
the Public Utility Holding Company Act, as amended by the Energy Policy Act of
1992.
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Federal Power Act. Under the Federal Power Act, FERC has exclusive
jurisdiction over the rates, terms and conditions of wholesale sales of
electricity and the transmission of electricity in interstate commerce by
"public utilities." Public utilities that are subject to FERC's jurisdiction
must file rates with FERC applicable to their wholesale sales or transmission
of electricity. Our business includes the sale of power at wholesale, and our
subsidiaries that make such sales are public utilities under the Federal Power
Act. All but one of our subsidiaries that sell electricity are exempt or have
been granted waivers from many of the accounting, recordkeeping and reporting
requirements that are imposed on public utilities with cost-based rate
schedules. As is customary with such orders, FERC reserved the right to revoke
or limit our subsidiaries' market-based rate authority if FERC subsequently
determines that any of these subsidiaries has excess market power. If FERC were
to revoke or limit this market-based rate authority, we would have to file, and
obtain FERC's acceptance of, cost-based rate schedules for all or some of our
wholesale power sales. In addition, the loss of market-based authority could
subject us to the accounting, recordkeeping and reporting requirements that
FERC imposes on public utilities with cost-based rate schedules.
In addition, FERC has approved on a temporary basis the imposition of price
caps and market mitigation plans restricting the amount that can be charged by
electricity generators and marketers in particular markets, such as measures
recently approved for the California, New York and New England markets. On July
25, 2001, FERC ordered that refunds may be due from sellers who engaged in
transactions in the California markets between October 2, 2000 and June 20,
2001, including ET-Power. In connection with the FERC proceeding, on August 17,
2001, the California ISO submitted data indicating that ET-Power may be
required to refund approximately $26 million. Using what we believe to be the
same methodology (including pricing information provided by the California
ISO), we believe that the amount of the refund owed by ET-Power, excluding
offsets, is significantly less. The methodology and its implementation by the
California ISO remain subject to FERC proceedings. Given this uncertainly and
the fact that we are reconciling these computations with the California ISO,
management is currently unable to determine the amount that may ultimately be
determined to be due. In addition, FERC has indicated that unpaid amounts owned
by the California ISO and the California Power Exchange may be used as offsets
to any refund obligations. We estimate that ET-Power is currently owed
approximately $22 million that could be used as an offset to any potential
refund obligation. Finalization of all these amounts will be subject to the
ongoing FERC proceeding.
FERC has also instituted a separate procedure to evaluate the potential for
refunds in the Pacific Northwest region. These types of initiatives could have
an adverse impact on our financial performance.
FERC also regulates the rates, terms and conditions for electric
transmission in interstate commerce. Tariffs established under FERC regulation
provide us with access to transmission lines, which enable us to sell the
energy we produce into competitive markets for wholesale energy. In April 1996,
FERC issued an order requiring all public utilities to file "open access"
transmission tariffs. Some utilities are seeking permission from FERC to
recover costs associated with stranded investments through add-ons to their
transmission rates. To the extent that FERC will permit these charges, the cost
of transmission may be significantly increased and may affect the cost of our
operations. FERC is also encouraging the restructuring of transmission
operations through the use of independent system operators and regional
transmission groups. Typically, the establishment of these entities results in
the elimination or reduction of transmission charges imposed by successive
transmission systems. The full effect of these changes on us is uncertain at
this time.
The Federal Power Act also gives FERC authority to license non-federal
hydroelectric projects on navigable waterways and federal lands. FERC
hydroelectric licenses are issued for 30 to 50 years. All of our hydroelectric
and pumped storage projects are licensed by FERC. These licenses expire
periodically and our current licenses for the various hydroelectric projects
will expire at different times between 2001 and 2020. Before the expiration of
a FERC license, the current licensee may apply for a new license. FERC may then
decide to issue a new license to the existing licensee, issue a license to a
new licensee that applied for the license, order the project to be taken over
by the federal government with compensation to the licensee, or
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order the decommissioning of the project at the owner's expense. The
relicensing process often involves complex administrative proceedings that may
take as long as ten years. Generally, the relicensing process begins five years
before the license expiration date. If the relicensing is not complete by the
end of the term of the existing license, FERC issues annual licenses to permit
a hydroelectric facility to continue operation pending conclusion of the
relicensing process. The relicensing process itself is costly and time-
consuming. As part of the relicensing process, the responsible state agency
issues a water quality certification under Section 401 of the Federal Clean
Water Act. Obtaining the certification may require the diversion of water from
power production or the construction of new facilities to improve water
quality, including temperature.
FERC issued a new license for our projects located on the Deerfield River on
April 7, 1997 and a new license application for the Fifteen Mile Falls project
(located on the Connecticut River) was filed July 30, 1999 and is still
pending. This relicensing proceeding is being undertaken through FERC's
alternative collaborative process rather than through its more traditional,
formal administrative process. No competing license applications have been
filed for these projects and there is no indication that FERC will decommission
any of these projects. Although the license for the Fifteen Mile Falls project
expired on July 31, 2001, FERC has granted us an annual extension of the
license and we anticipate annual extensions will be granted until such time
that a new license is issued. Even if new licenses are issued, FERC may impose
additional restrictions or requirements on the operation of the projects, such
as operational restrictions or requirements for additional non-power facilities
such as a fish passage or recreational facility. These additional restrictions
or requirements could add significant costs to our operations or reduce
revenues. Any denial of our license applications or imposition of additional
restrictions or requirements may have a material adverse effect on our
business, financial condition and results of operations.
In 1994, FERC adopted a policy statement in which it asserted that it has
authority over the decommissioning of licensed hydroelectric projects being
abandoned or denied a new license. However, FERC has recognized in the process
leading to the policy statement that mandated project removal would occur in
only rare circumstances. FERC also declined to require any generic funding
mechanism to cover decommissioning costs. If a project is decommissioned, then
the licensee may incur substantial costs.
Natural Gas Regulation. Under the Natural Gas Act, FERC has jurisdiction
over, among other things, the construction, expansion or abandonment of
pipelines and related facilities used in the transportation, storage and sale
(for resale) of natural gas in interstate commerce and the rates, terms and
conditions for the transportation and sale (for resale) of natural gas in
interstate commerce. Both the GTN and Iroquois pipelines are considered
"natural gas companies" under the Natural Gas Act, and we hold the required
certificates of public convenience and necessity from FERC to operate these
pipelines and related facilities and properties. The North Baja pipeline has
filed an application with FERC for a certificate of public convenience and
necessity to construct and operate its proposed system, and will be a "natural
gas company" upon receipt of a certificate.
Under the Natural Gas Act and FERC regulations, interstate pipelines are
allowed to charge a FERC-approved just and reasonable rate for service.
Interstate pipelines are also authorized to charge negotiated rates for service
if their customers have an option to take service under the FERC-approved,
cost-based recourse rates. Under FERC policy, recourse rates are established
using a "straight-fixed variable" rate design under which the pipelines recover
all fixed costs under the demand charge component of their rates. Both our GTN
and Iroquois pipelines recover almost all fixed costs in this manner. As
necessary, our GTN and Iroquois pipelines file applications with FERC for
changes in rates and charges that would allow us to continue to recover
substantially all of our costs of providing service to transportation
customers, including a reasonable rate of return. These rates are normally
allowed to become effective after a suspension period, and in certain cases are
subject to refund under applicable law until FERC issues an order on the
allowable level of rates. To date, all customers that have subscribed for
capacity on the North Baja pipeline system have elected fixed price, negotiated
rate contracts under which the rate for service remains fixed for the full term
of the contract.
In addition, the National Energy Board of Canada, or NEB, and Canadian gas-
exporting provinces issue various licenses and permits for the removal of gas
from Canada, and the Mexican Comision Reguladoro de
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Energia, or CRE, issues various licenses and permits for the importation of gas
into Mexico. These requirements are similar to the requirements of the U.S.
Department of Energy for the importation and exportation of gas. Regulatory
actions by the NEB can have an impact on the ability of our customers on the
GTN and Iroquois systems to import Canadian gas and for transportation over our
pipeline system. In addition, actions of the NEB and Northern Pipeline Agency,
or NPA, in Canada can affect the ability of Canadian pipelines to construct any
future facilities necessary for the transportation of gas to the
interconnection with our GTN pipeline system at the United States-Canada
border.
Similarly, regulatory actions by CRE can have an impact on the ability of
our customers on the North Baja pipeline system to export gas to Mexico and can
affect the ability of Mexican pipelines to construct future facilities
necessary to receive additional deliveries of gas from the North Baja pipeline
system.
Public Utility Holding Company Act. The Public Utility Holding Company Act,
or PUHCA, provides that any entity which 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
PUHCA regulations and certain SEC requirements, unless such entity is exempt
under the provisions of PUHCA or is declared not to be a holding company by
order of the SEC. Registered holding companies under PUHCA are required to
limit their utility operations to a single integrated utility system. A public
utility company that is a subsidiary of a registered holding company under
PUHCA is subject to financial and organizational regulations, including
approval of certain of its financing transactions by the SEC.
PG&E Corporation is not a registered holding company under PUHCA. PG&E
Corporation and its subsidiaries, including us, are exempt from all the
provisions of PUHCA except Section 9(a)(2), although the California Attorney
General recently filed a petition with the SEC to revoke this exemption. See
"Relationship with PG&E Corporation and Related Transactions" for additional
information regarding the petition filed by the California Attorney General.
Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of
1992. The enactment of the Public Utility Regulatory Policies Act of 1978 and
the Energy Policy Act of 1992, or PURPA, in 1978 provided incentives for the
development of QFs, which are basically cogenerating facilities and small power
production facilities that utilize certain alternative or renewable fuels. QF
status conveys two primary benefits. First, regulations under PURPA exempt QFs
from PUHCA, most provisions of the Federal Power Act and the state laws
concerning rates, and financial and organizational requirements of electric
utilities. Second, FERC's regulations under PURPA require that (1) electric
utilities purchase electricity generated by QFs at a price based on the
purchasing utility's full avoided cost of producing power, (2) the electric
utilities must sell back-up, interruptible, maintenance and supplemental power
to the QF on a non-discriminatory basis, and (3) the electric utilities must
interconnect with any QF in its service territory and, if required, transmit
power if they do not purchase it. If a facility were to lose QF status, we
could attempt to avoid regulation under PUHCA by qualifying the project as an
exempt wholesale generator, or EWG, under the Energy Policy Act of 1992.
EWGs are not regulated under PUHCA, but are subject to FERC and state public
utility commission regulatory reviews, including rate approval. EWGs do not
enjoy the same statutory and regulatory exemptions from state regulation as are
granted to QFs. In fact, because EWGs are only allowed to sell power at
wholesale, their rates must receive initial approval from FERC rather than the
states. All but one of our operating EWGs that have sought rate approval from
FERC have been granted market-based rate authority, which allows FERC to waive
the accounting, recordkeeping and reporting requirements imposed on public
utilities described above.
If there occurs a material change in facts that might affect any of our
subsidiaries' eligibility for EWG status, within 60 days of the material
change, the EWG subsidiary must (i) file a written explanation of why the
material change does not affect its EWG status, (ii) file a new application for
EWG status, or (iii) notify FERC that it no longer wishes to maintain EWG
status. If any of our subsidiaries were to lose EWG status, we, along with our
subsidiaries, would be subject to regulation under PUHCA as a public utility
company. Absent a substantial restructuring of our business, it would be
difficult for us to comply with PUHCA without a material adverse effect on our
business.
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Department of Energy. In addition to FERC's jurisdiction over us as
discussed above, our transmission business' importation of natural gas from
Canada is subject to approval by the Office of Fossil Energy of the DOE. We are
also subject to DOE's approval with respect to the exportation of power to
Canada and Mexico, which we have engaged in through our power marketing
business.
State Regulation. In addition to federal laws and regulation, we are also
subject to various state regulations. First, public utility regulatory
commissions at the state level are responsible for approving rates and other
terms and conditions under which public utilities purchase electric power from
independent power producers. As a result, power sales agreements, which we
enter into with such utilities, are potentially subject to review by the public
utility commissions, through the commissions' power to review the process by
which the utilities have entered into these agreements. Second, state public
utility commissions also have the authority to promulgate regulations for
implementing some federal laws, including certain aspects of PURPA. Third, some
public utility commissions have asserted limited jurisdiction over independent
power producers. For example, in New York the state public utility commissions
have imposed limited requirements involving safety, reliability, construction
and the issuance of securities by subsidiaries operating assets located in that
state. Fourth, state regulators have jurisdiction over the restructuring of
retail electric markets and related deregulation of their electric markets.
Finally, states may also assert jurisdiction over the siting, construction and
operation of our facilities.
Environmental Regulatory Matters
We are subject to a number of federal, state and local requirements relating
to:
. the protection of the environment; and
. the safety and health of personnel and the public.
These requirements relate to a broad range of our activities, including:
. the discharge of pollutants into the air and water;
. the identification, generation, storage, handling, transportation,
disposal, recordkeeping, labeling, reporting of, and emergency response
in connection with, hazardous and toxic materials and wastes, including
asbestos, associated with our operations;
. land use, including wetlands protection;
. noise emissions from our facilities; and
. safety and health standards, practices and procedures that apply to the
workplace and to the operation of our facilities.
In order to comply with these requirements, we may need to spend substantial
amounts and devote other resources from time to time to:
. construct or acquire new equipment;
. acquire permits and/or marketable allowances or other emission credits
for facility operations;
. modify or replace existing equipment; and
. remove areas of degraded lead paint and asbestos, clean up or
decommission waste disposal areas, fuel storage and management facilities
and other locations and facilities, including coal mine refuse piles and
generating facilities.
We believe we are in substantial compliance with applicable environmental
laws and applicable health and safety laws. However, we cannot assure you that
additional costs will not be incurred or operations at some of our facilities
will not be limited as a result of new interpretations or application of
existing laws and regulations, the enactment of more stringent requirements, or
the identification of conditions that could result in additional obligations or
liabilities.
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We anticipate spending up to approximately $330 million, net of insurance
proceeds, through 2008 for environmental compliance at currently operating
facilities, which primarily addresses: (a) new Massachusetts air regulations
issued on May 11, 2001 affecting our Brayton Point and Salem Harbor Stations;
(b) wastewater permitting requirements that may apply to our Brayton Point,
Salem Harbor and Manchester Street Stations; and (c) requirements, to which we
agreed, that are reflected in a consent decree concerning wastewater treatment
facilities at our Salem Harbor and Brayton Point Stations (all of which are
discussed in the "Air Emissions" and "Water Discharges" sections that follow).
If we do not comply with environmental requirements that apply to our
operations, regulatory agencies could seek to impose on us civil,
administrative and/or criminal liabilities, as well as seek to curtail our
operations. Under some statutes, private parties could also seek to impose
civil fines or liabilities for property damage, personal injury and possibly
other costs. We cannot assure you that lawsuits or other administrative actions
against our generating facilities will not be filed or taken in the future. If
an action is filed against us or our generating facilities, this could require
substantial expenditures to bring our generating facilities into compliance and
have a material adverse effect on our financial condition, cash flows and
results of operations.
Air Emissions
Air Emissions Generally. Our facilities are subject to the Federal Clean Air
Act and many state laws and regulations relating to air pollution. These laws
and regulations cover, among other pollutants, those contributing to the
formation of ground-level ozone, carbon monoxide, sulfur dioxide or SO2,
nitrogen oxides or NOx, and particulate matter. As a general matter, our
generating facilities emit these pollutants at levels within regulatory
requirements. Fossil fuel-fired electric utility plants are usually major
sources of air pollutants, and are therefore subject to substantial regulation
and enforcement oversight by the applicable governmental agencies. Various
multi-pollutant initiatives have been, or are expected to be, introduced in the
U.S. Senate and House of Representatives, including Senate Bill 556 and House
Resolutions 1256 and 1335. These initiatives include limits on the emissions of
NOx, SO2, mercury and CO2. Certain of these proposals would allow the use of
trading mechanisms to achieve or maintain compliance with the proposed rules.
Pollutants Contributing to Ozone. Most of our generating facilities burn
fossil fuels, primarily coal, oil or natural gas to produce electricity. The
combustion of fossil fuels produces NOx, which can react chemically with
organic and other compounds present in the lower portion of the atmosphere to
form ozone. Ozone in the lower portion of the atmosphere, ground-level ozone,
is considered by government health and environmental protection agencies to be
a human health hazard, which has prompted both the federal and state
governments to adopt stringent air emission requirements for fossil fuel-fired
generating stations. These requirements are designed to reduce emissions that
contribute to ozone formation, with particular emphasis on NOx.
Nitrogen Oxides. A multi-state memorandum of understanding dealing with the
control of NOx air emissions from major emission sources was signed by the
Ozone Transport Commission states in the Mid-Atlantic and Northeastern states.
The memorandum of understanding and underlying state laws establish a regional
three-phase plan for reducing NOx emissions from electric generating units and
large industrial boilers within the Ozone Transport Region. Implementation of
Phase 1 was the installation of Reasonably Available Control Technology, or
RACT, no later than May 31, 1995. This was successfully completed. Phase 2
commenced in 1999 and will continue through 2002. Phase 3 will begin in 2003.
Among other things, the rules implementing Phases 2 and 3:
. establish NOx budgets, or emissions caps during the ozone season of May
through September;
. establish methodology to allocate the allowances to affected sources
within the budget; and
. require an affected source to account for ozone season NOx emissions
through the surrender of NOx allowances.
The number of NOx allowances available to each facility under the ozone
season budget decreases as the program progresses and thus forces an overall
reduction in NOx emissions. Under regulatory systems of this type, we may
purchase NOx allowances from other sources in the area in addition to those
that are allocated to
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our facilities, instead of installing NOx emission control systems at our
facilities. Depending on the market conditions, the purchase of extra
allowances for a portion of our NOx budget requirements may minimize the total
cost of compliance. During Phase 3, we will receive fewer allowances under a
reduced NOx budget. We are currently formulating our Phase 3 strategy. Our plan
to meet the Phase 3 budget level for Salem Harbor and Brayton Point will
require a combination of allowance purchases and emission control technologies.
We expect that the emission reductions to be required under regulations
recently issued by the Commonwealth of Massachusetts (described in "--State
Initiatives" below) significantly reduce our need for allowance purchases.
Separate and apart from the requirements described above, the U.S.
Environmental Protection Agency, or EPA, has initiated several regulatory
efforts that are intended to impose limitations on major NOx sources located in
the eastern United States and the Midwest in order to reduce the formation and
regional transport of ozone. Such regulatory efforts include EPA's "Section 126
Rule" and the "NOx SIP Rule call," which together would establish a federal NOx
emissions cap-and-trade program that would apply to some existing utilities and
large industrial sources located in midwestern and eastern states whose
emissions EPA has determined contribute to air quality problems in "downwind"
states (generally in the northeast corner of the United States). Aspects of
both rules remain the subject of litigation.
Sulfur Dioxide. The Clean Air Act acid rain provisions require substantial
reductions in SO2 emissions. Implementation of the acid rain provisions is
achieved through a total cap on SO2 emissions from affected units and an
allocation of marketable SO2 allowances to each affected unit. Operators of
electric generating units that emit SO2 in excess of their allocations can buy
additional allowances from other affected sources. We currently project the
number of SO2 allowances allocated to our New England units will be greater
than projected SO2 emissions through 2010. Whether we will have an excess or
deficit of SO2 allowances for any given year will depend, in part, on the
capacity utilization of each of the units. However, depending on the extent of
any allowance deficits, the price and the availability of allowances and other
regulatory factors, we will consider changing to low-sulfur coal or other
emission control technologies to maintain compliance.
Visibility Impairment Rules. EPA has promulgated regulations relating to
reduction in the impairment of visibility resulting from man-made pollution.
The regulations have been challenged in court and the ultimate impact of these
regulations on our facilities in uncertain. Even under the existing regulations
in light of the compliance date set forth therein, we do not expect any impact
on our facilities until 2012 and beyond.
Carbon Dioxide. In November 1998, the United States became a signatory to
the Kyoto Protocol to the United Nations Framework Convention on Climate
Change. The Kyoto Protocol calls for developed nations to reduce their
emissions of greenhouse gases, which are believed to contribute to global
climate change. Carbon dioxide, which is a major byproduct of the combustion of
fossil fuel, is considered to be a greenhouse gas. The Kyoto Protocol, however,
will not become enforceable law in the United States unless and until the U.S.
Senate ratifies it. Early this year, the Bush Administration announced that it
would not support ratification of the Kyoto protocol and did not see the Kyoto
process as a workable means of addressing concerns about climate change.
Nonetheless, international negotiations, which could result at some point in
mandatory CO2 reductions at United States facilities, continue. Moreover, in
addition to the Kyoto Protocol, other initiatives may address CO2 emissions in
the future. For example, several bills have been introduced in Congress that
address, among other things, CO2 emissions from power plants. If the U.S.
Senate ultimately ratifies the Kyoto Protocol or if alternative greenhouse gas
emission reduction requirements are implemented, including state-imposed
requirements, the resulting limitations on power plant carbon dioxide emissions
could have a material adverse impact on all fossil fuel-fired facilities,
including our facilities. The Massachusetts regulations recently made public,
referred to in "--State Initiatives," impose requirements regarding CO2
emissions that will apply to our Brayton Point and Salem Harbor facilities.
Particulates. EPA issued a new and more stringent national ambient air
quality standard, or NAAQS, in July 1997 for fine particulate matter. Under the
time schedule announced by EPA when the new standard for fine particulates was
adopted, geographical areas that were non-attainment areas for the standard
were to be
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designated in 2002, and control measures for significant sources of fine
particulate emissions were to be identified in 2005. On May 14, 1999, however,
the U.S. Court of Appeals for the District of Columbia Circuit vacated and
remanded the fine particulate standard to EPA for further justification. On
February 27, 2001, the Supreme Court, in Whitman v. American Truck
Associations, Inc., reversed the circuit court's judgment on this issue and
remanded the case to the Court of Appeals to dispose of any other preserved
challenges to the particulate matter and ozone standards. As a result, there is
no presently enforceable standard for fine particulates, and we do not know
what impact, if any, future revision to this standard may have on our
facilities. If an ambient air quality standard for fine particulates is
promulgated, further NOx and SO2 reductions may be required for those of our
facilities located in areas where sampling indicates the ambient air does not
comply with the final standards that are adopted.
New Source Review Compliance. EPA also has been conducting a nationwide
enforcement investigation regarding the historical compliance of coal-fueled
electric generating stations with various permitting requirements of the Clean
Air Act. Specifically, EPA and the U.S. Department of Justice have recently
initiated enforcement actions against a number of electric utilities, several
of which have entered into substantial settlements for alleged Clean Air Act
violations related to modifications (sometimes more than 20 years ago) of
existing coal-fired generating facilities. In May 2000, we received a request
for information seeking detailed operating and maintenance histories for the
Salem Harbor and Brayton Point power plants and, in November 2000, EPA visited
both facilities. We believe that the request for information is part of EPA's
industry-wide investigation of coal-fired power plants' compliance with the
Clean Air Act requirements governing plant modifications. We also believe that
any changes we made to these plants were routine maintenance or repair and,
therefore, did not require permits. EPA has not issued a notice of violation or
filed any enforcement action against us at this time. Nevertheless, if EPA
disagrees with our conclusions with respect to the changes we made at the
facilities, and successfully brings an enforcement action against us, then
penalties may be imposed and further emission reductions might be necessary at
these plants.
In addition, EPA continues to evaluate revisions to the New Source Review
requirements. These new requirements will likely be challenged by various
interested groups, and it may be several years before they take effect.
Depending on the stringency of future requirements, the potential cost of
compliance could be significant.
Mercury. EPA has announced that it will regulate steam electric generating
plants under Title III of the Clean Air Act, which addresses emissions of
hazardous air pollutants from specific industrial categories. Power plants are
a source of mercury air emissions. EPA recently signed a regulatory finding
that commits it to propose a mercury-emissions rule applicable to fossil-fuel
fired power plants by 2003 and to promulgate a final rule by 2004. According to
this regulatory finding, affected facilities will have to comply with this
final rule in 2007-2008. In addition, the Massachusetts regulations promulgated
on May 11, 2001 (discussed in the following paragraph) address mercury
emissions. The rulemaking process will likely include significant stakeholder
and public participation both before and after the emission standards are
proposed. The applicable control levels are uncertain, as are the costs of
compliance with these future rules.
State Initiatives. From time to time various states in which our facilities
are located consider the adoption of air emissions standards that may be more
stringent than those imposed by EPA. On May 11, 2001, the Massachusetts
Department of Environmental Protection, or DEP, issued regulations imposing new
restrictions on emissions of NOx and SO2, mercury and carbon dioxide from
existing coal-fired power plants. These restrictions will impose more stringent
annual and monthly limits on NOx and SO2 emissions than currently exist and
will take effect in stages, beginning in October 2004 if no permits are needed
for the changes necessary to comply, and beginning in 2006 if such permits are
needed. DEP has informed USGen New England that, based upon its current
understanding of the facilities' plans for compliance with the new regulations,
it believes that permits will be needed and that the initial compliance date
will therefore be 2006. However, the need for permits triggers an obligation to
meet Best Available Control Technology, or BACT, requirements. Compliance with
BACT at the facilities could require implementation of controls beyond those
otherwise necessary to meet the emissions standards in the new regulations.
Mercury emissions are capped as a
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first step and must be reduced by October 2006 pursuant to standards to be
developed. Carbon dioxide emissions are regulated for the first time and must
be reduced from recent historical levels. We believe that compliance with the
carbon dioxide caps can be achieved through implementation of a number of
strategies, including sequestrations and offsite reductions. Various testing
and recordkeeping requirements are also imposed.
By 2002, we plan to have approximately 5,100 MW of generating capacity in
operation in New England. The new Massachusetts regulations affect primarily
our Brayton Point and Salem Harbor generating facilities, representing
approximately 2,300 MW. Through 2006, it may be necessary to spend
approximately $265 million to comply with these regulations. In addition, with
respect to approximately 600 MW (or about 12%) of our New England capacity, we
may need to implement fuel conversion, limit operations, or install additional
environmental controls. These new regulations require that we achieve specified
emission levels earlier than the dates included in a previous Massachusetts
initiative to which we had agreed.
Water Discharges
The federal Clean Water Act generally prohibits the discharge of any
pollutants, including heat, into any body of surface water, except in
compliance with a discharge permit issued by a state environmental regulatory
agency and/or EPA. All of our facilities that are required to have such permits
either have them or have timely applied for extensions of expired permits and
are operating in substantial compliance with the prior permit. At this time,
three of the fossil-fuel plants owned and operated by USGen New England
(Manchester Street, Brayton Point and Salem Harbor stations) are operating
pursuant to permits that have expired. For the facilities whose NPDES permits
have expired, permit renewal applications are pending, and we anticipate that
all three facilities will be able to continue to operate in substantial
compliance with prior permits until new permits are issued. It is estimated
that USGen New England's cost to comply with new permit conditions could be
approximately $60 million through 2005. It is possible that the new permits may
contain more stringent limitations than the prior permit.
At Brayton Point, unlike the Manchester Street and Salem Harbor generating
facilities, we have agreed to meet certain restrictions that were not in the
expired NPDES permit. In October 1996, EPA announced its intention to seek
changes in Brayton Point's NPDES permit based on a report prepared by the Rhode
Island Department of Environmental Management, which alleged a connection
between declining fish populations in Mt. Hope Bay and thermal discharges from
the Brayton Point once-through cooling system. In April 1997, the former owner
of Brayton Point entered into a Memorandum of Agreement, or MOA, with various
governmental entities regarding the operation of the Brayton Point station
cooling water systems pending issuance of a renewed NPDES permit. This MOA,
which is binding on us, limits on a seasonal basis the total quantity of heated
water that may be discharged to Mt. Hope Bay by the plant. While the MOA is
expected to remain in effect until a new NPDES permit is issued, it does not in
any way preclude the imposition of more stringent discharge limitations for
thermal and other pollutants in a new NPDES permit and it is possible that such
limitations will in fact be imposed. If such limitations are imposed, we cannot
assure you that they will not have a material adverse effect on our financial
condition, cash flows and results of operations.
In addition, EPA, as well as local environmental groups, have previously
expressed concern that the metal vanadium is not addressed at our Brayton Point
or Salem Harbor station under the terms of the old NPDES permit and it may
raise this issue in upcoming NPDES permit negotiations. Based upon the lack of
an identified control technology, we believe it is unlikely that EPA will
require that vanadium be addressed pursuant to a NPDES permit. However, if EPA
does insist on including vanadium in our NPDES permit, we may have to spend a
significant amount to comply with such a provision.
EPA has issued for public comment proposed rules which would impose uniform,
minimum technology requirements on new cooling water intake structures. Similar
rules for existing intake structures are expected to be proposed in the summer
of 2001. It is not known at this time what requirements the final rules for
existing intake structures will impose and whether our existing intake
structures will require modification as a result of such requirements.
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In July 2000, EPA issued final rules for the implementation of the total
maximum daily load, or TMDL, program of the Clean Water Act. The goal of the
TMDL rules is to establish, over the next 15 years, the maximum amounts of
various pollutants that can be discharged into waterways while keeping those
waterways in compliance with water quality standards. The establishment of TMDL
values may eventually result in more stringent discharge limits in each
facility's wastewater discharge permit. Such limits may require our facilities
to install additional wastewater treatment, modify operational practices or
implement other wastewater control measures. Certain members of Congress have
expressed to EPA concern about the TMDL program with respect to such issues as
the scientific validity of data used to establish TMDLs, as well as the costs
to implement the program.
Solid Waste; Toxics
Our facilities are subject to the requirements promulgated by EPA under the
Resource Conservation and Recovery Act, or RCRA, and the Comprehensive
Environmental Response, Compensation and Liability Act, along with other state
hazardous waste laws and other environmental requirements. We, on an on-going
basis, assess measures that may need to be taken to comply with federal, state
and local laws and regulations related to hazardous materials and hazardous
waste compliance and remediation activities. In connection with USGen New
England's purchase of certain electric generating facilities from the New
England Electric System, or NEES, in 1998, we have assumed the onsite
environmental liability of these acquired facilities. We have obtained
pollution liability and environmental remediation insurance coverage to limit,
to a certain extent, the financial risks with respect to these onsite
liabilities. We did not acquire any offsite liability associated with the past
disposal practices of the prior owner.
During April 2000, an environmental group served USGen New England and other
of our subsidiaries with a notice of its intent to file a citizen's suit under
RCRA. The group stated that it planned to allege that USGen New England, as the
generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point,
has contributed and is contributing to the past and present handling, storage,
treatment and disposal of wastes at those facilities which may present an
imminent and substantial endangerment to the public health or the environment.
During September 2000, USGen New England signed a series of agreements with the
Massachusetts Department of Environmental Protection and the environmental
group that address and resolve these matters. The agreements, which have been
filed in federal court and are now incorporated in a consent decree, require,
among other things, that USGen New England alter its existing wastewater
treatment facilities at both facilities by replacing certain unlined treatment
basins, submit and implement a plan for the closure of such basins, and perform
certain environmental testing at the facilities. Although the outcome of such
environmental testing could lead to higher costs, the total cost of these
activities is expected to be approximately $21 million, and they are underway.
Changes in the laws governing disposal of coal ash generated by our coal-
fired generating facilities to classify coal ash as a hazardous waste or
otherwise restrict the disposal of coal ash could increase our costs and expose
us to greater potential liabilities for environmental remediation. The ash
disposal sites used by our coal-fired generating facilities are permitted under
current state and local regulations. It is possible that we could face
increased disposal costs as a result of regulatory (federal, state or local)
changes governing the disposal of coal ash.
Many of our New England generating facilities are more than 40 years old,
and as a result contain asbestos insulation and other asbestos containing
materials, as well as lead-based paint. Existing state and federal rules
require the proper management and disposal of these potentially toxic
materials. We have developed a management plan that includes proper maintenance
of existing non-friable asbestos installations, and removal and abatement of
asbestos containing materials where necessary because of maintenance, repairs,
replacement or damage to the asbestos itself. We have also implemented a lead-
based paint removal program at some of our facilities. We have planned for the
proper management, abatement and disposal of asbestos and lead-based paint at
our generating facilities in our financial planning.
In April 1997, EPA expanded the list of industry groups required to report
the Toxic Release Inventory under Section 313 of the Emergency Planning and
Community Right-to-Know Act to include electric utilities.
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Our fossil fuel operating facilities are required to complete a toxic chemical
inventory release form for each listed toxic chemical manufactured, processed
or otherwise used in excess of threshold levels for the applicable reporting
year. The purpose of this requirement is to inform EPA, states, localities and
the public about releases of toxic chemicals to the air, water, and land that
can pose a threat to the community.
Employees
As of June 30, 2001, we employed approximately 2,300 people. Of these
employees, approximately 530 are covered by collective bargaining agreements.
The collective bargaining agreements expire at various dates between November
1, 2001 and December 31, 2001. We have never experienced a work stoppage,
strike, or other similar disruption. We consider our relations with our
employees to be good.
Facilities/Properties
Our corporate offices currently occupy approximately 240,000 square feet of
leased office space in several buildings in Bethesda and Rockville, Maryland.
In addition to our corporate office space, we lease or own various real
property and facilities relating to our generating facilities and development
activities. Our principal generating facilities are generally described under
the descriptions of our regional asset portfolios contained elsewhere in this
prospectus. We believe that we have title to our facilities in accordance with
standards generally accepted in the energy industry, subject to exceptions,
which, in our opinion, would not have a material adverse effect on the use or
value of the facilities. All of our independent power projects are pledged to
lenders under non-recourse project loans.
We believe that all of our existing office and generating facilities,
including the facilities under construction, are adequate for our needs through
calendar year 2001. 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 various litigation matters in the ordinary course of our
business. Except as described below, there is no litigation in which we are
currently involved that could directly, either individually or in the
aggregate, have a material adverse effect on our financial condition or results
of operations.
Litigation Involving Generating Projects
Logan Generating Company, LP, or Logan, one of our unconsolidated
subsidiaries, initiated an arbitration proceeding against the purchaser of
electricity produced by its generating facility, seeking a declaration that the
power purchase agreement under which it makes sales to the purchaser allows it
to establish certain procedures for determining Logan's heat rate upon which
energy payments to Logan for the electricity it sells are based, and that the
procedure which Logan has established for this purpose is proper under the
power purchase agreement. In addition, Logan is seeking to recover the costs of
the arbitration. The electricity purchaser counterclaimed contending that
Logan's heat rate testing procedure is a breach of the power purchase
agreement, and it seeks (1) an order declaring that Logan's heat rate testing
procedure must conform to that used by the plant's construction contractor in
final acceptance testing, (2) damages and other relief based in part on
recalculation of past energy payments using heat rates lower than those
reported by Logan in prior invoices in the amount of approximately $7 million,
plus interest, and (3) an order declaring that the purchaser is allowed to
terminate the power purchase agreement because of Logan's heat rate testing
procedure. The power purchaser is also seeking to recover the cost of the
arbitration. Hearings are underway and it is not possible to predict whether an
unfavorable outcome is likely or estimate the amount of a potential loss.
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Energy Trading Litigation
A power marketer filed suit in October 1998 in the State of New York Supreme
Court (County of Onondaga) against ET-Power. The power marketer essentially
claims that ET-Power breached various alleged agreements between the parties
that the power marketer asserts were created at the time certain sales of
electricity by the power marketer, ET-Power, and others were scheduled for
delivery. The power marketer further claims that: (1) ET-Power tortiously
interfered with power sales agreements the power marketer had executed with
certain third parties and (2) ET-Power made certain misrepresentations that
were fraudulent or negligent. In addition, the power marketer alleges that ET-
Power was unjustly enriched as a result of the foregoing. This power marketer
seeks to recover damages of approximately $6 million, an unspecified amount of
punitive damages, costs and other relief, including monies allegedly received
by ET-Power as a result of its purported unjust enrichment. In 1999, the court
granted the power marketer's motion to join two other power marketers in the
lawsuit. These other power marketers seek recovery from ET-Power of
approximately $.7 million. We believe that these complaints are without merit
and intend to present a vigorous defense. At this time, management does not
believe that the outcome of this litigation will have a material adverse effect
on our financial condition or results of operations.
A creditor's involuntary bankruptcy petition was filed in the United States
Bankruptcy Court, District of Connecticut (Bridgeport Division) in August 1998
against a power marketer. ET-Power is an unsecured creditor of this entity. As
part of the bankruptcy, the bankruptcy court created a liquidating trust and
appointed a trustee to act on behalf of the trust. The trustee has alleged,
among other things, that ET-Power improperly terminated transactions with the
bankrupt power marketer. In December 1999, ET-Power filed an action in federal
court in Texas seeking a declaration from the court that termination of the
transactions with the bankrupt power marketer was not a breach of the
agreements. Subsequently, the trustee filed suit in the bankruptcy court
alleging, among other things, breach of contract, various torts, unjust
enrichment, improvement in position and preference. The lawsuit seeks
approximately $32 million in actual damages, plus punitive damages in an
unspecified amount. The parties have agreed to dismiss the Texas action and the
bankruptcy action without prejudice. They have also agreed that the case, if
not settled, would be heard in federal court in Connecticut. The parties are
now participating in various mediation proceedings underway in connection with
the bankruptcy action and discovery is continuing. We believe that these
complaints are without merit and intend to present a vigorous defense. At this
time, management does not believe that the outcome of this litigation will have
a material adverse effect on our financial condition or results of operations.
On May 14, 2001, NSTAR Electric & Gas Corporation, or NSTAR, the Boston-area
retail electric distribution utility holding company, filed a complaint at FERC
contesting the market-based rate authority of ET-Power and affiliates of Sithe
Energies, Inc., or Sithe. In support of its complaint, NSTAR argues that the
Northeastern Massachusetts Area, or NEMA, at times suffers transmission
constraints which limit the delivery of power into NEMA and that ET-Power and
Sithe possess market power based on their share of generation within NEMA.
NSTAR requests remedies including revocation of the suppliers' market-based
pricing authority during periods of transmission congestion into NEMA,
divestiture of generation resources in NEMA, imposition of a rate cap on the
suppliers' generation resources during transmission constraints based on the
marginal cost of production of those resources, and more effective and open
exercise of market monitoring and mitigation by ISO-New England, the
independent system operator for the New England control area, or NEPOOL.
Under the NEPOOL market rules and procedures, ISO-New England is empowered
to monitor and mitigate bids during periods of transmission congestion. We
believe that ISO-New England has actively mitigated bids and has used its
authority to minimize the impact of transmission constraints on costs within
NEMA and that ET-Power has operated its resources in compliance with NEPOOL
market rules and procedures and applicable law. In addition, ET-Power and its
affiliate, USGen New England, the entity which owns the generating assets
located in NEPOOL, have had their market-based rate authority confirmed by FERC
on two prior occasions. We believe that these complaints are without merit and
intend to present a vigorous defense. At this time, management does not believe
that the outcome of this litigation will have a material adverse effect on our
financial condition or results of operations.
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MANAGEMENT
Directors and Executive Officers
The following table provides information on our directors and executive
officers as of July 15, 2001:
Name Age Position
---- --- --------
Thomas G. Boren............. 52 President, Chief Executive Officer and
Director
P. Chrisman Iribe........... 50 President and Chief Operating Officer,
Eastern Region
Thomas B. King.............. 39 President and Chief Operating Officer,
Western Region
Lyn Maddox.................. 47 President and Chief Operating Officer,
Trading
Stephen A. Herman........... 57 Senior Vice President and General Counsel
John R. Cooper.............. 54 Senior Vice President, Finance
Thomas E. Legro............. 50 Vice President, Controller and Chief
Accounting Officer
Sarah M. Barpoulis.......... 36 Senior Vice President, Commercial
Operations, Trading
G. Brent Stanley............ 54 Senior Vice President, Human Resources and
Director
Peter A. Darbee............. 48 Director
Bruce R. Worthington........ 51 Director
Andrew L. Stidd............. 44 Director
Thomas G. Boren has been our President and Chief Executive Officer since
August 1999, and was elected to our board of directors in July 2000. He has
also served as Executive Vice President of PG&E Corporation since August 1999.
Mr. Boren was President and Chief Executive Officer of Southern Energy Inc.,
Southern Company's worldwide power plant, energy trading, and energy services
business from February 1992 to July 1999. He served as Senior Vice President
and later Executive Vice President of Southern Company from 1992 to July 1999.
Mr. Boren held senior management positions with Southern Company's utility
unit, Georgia Power Company, from 1981 to 1992.
P. Chrisman Iribe has been our President and Chief Operating Officer,
Eastern Region since July 2000. He has also served as Senior Vice President of
PG&E Corporation since December 16, 1998. Mr. Iribe previously served as
President and Chief Operating Officer of PG&E Generating Company, one of our
subsidiaries, from November 1998 to January 2000. From September 1997 to
November 1998, Mr. Iribe served as Executive Vice President and Chief Operating
Officer of PG&E Generating Company (formerly known as U.S. Generating Company).
Mr. Iribe held various other executive positions within U.S. Generating Company
from 1989 to September 1997. Prior to Mr. Iribe's joining U.S. Generating
Company in 1989, he was senior vice president for planning, state relations and
public affairs at ANR Pipeline Company (natural gas pipeline).
Thomas B. King has been our President and Chief Operating Officer, Western
Region since July 2000. He has also served as Senior Vice President of PG&E
Corporation since December 16, 1998. Mr. King has also served as President and
Chief Operating Officer of PG&E Gas Transmission, Northwest Corporation, one of
our subsidiaries, since November 1998. Prior to joining PG&E Gas Transmission
Company, he was President and Chief Operating Officer of Kinder Morgan Energy
Partners, L.P. (energy pipeline operations) from February 1997 to November
1998, and was Vice President, Commercial Operations for Enron Liquids, from
September 1995 to February 1997.
Lyn Maddox has been our President and Chief Operating Officer, Trading since
July 2000. He has also served as Senior Vice President of PG&E Corporation
since May 12, 1997. Mr. Maddox was President and Chief Operating Officer of
PG&E Energy Trading Corporation, one of our subsidiaries, from May 1997 to June
2000. Prior to that, Mr. Maddox was president of PennUnion Energy Services from
March 1995 to May 1997 and President and Chief Operating Officer of Brooklyn
Interstate Natural Gas Corporation from February 1989 to February 1995.
Stephen A. Herman has been our Senior Vice President and General Counsel
since July 2000. From April 1999 to April 2000, he was a partner in the law
firm of Latham & Watkins. He was Senior Vice President and
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General Counsel of U.S. Generating Company (subsequently PG&E Generating
Company) from August 1990 to April 1999. Prior to that, he was a partner with
the law firm of Kirkland & Ellis.
John R. Cooper has been our Senior Vice President, Finance since July 2000.
He served as Senior Vice President Finance and Chief Financial Officer of PG&E
Generating Company from August 1997 to June 2000. Prior to that time, Mr.
Cooper served as Senior Vice President, Finance for U.S. Generating Company
from March 1993 to August 1997.
Thomas E. Legro has been our Vice President, Controller and Chief Accounting
Officer since July 2001. From January 1994 to June 2001, Mr. Legro was Vice
President and Controller of Edison Mission Energy (independent power producer).
Sarah M. Barpoulis has been our Senior Vice President, Commercial
Operations, Trading since July 2000. She served as Senior Vice President of
PG&E Energy Trading from May 1998 to June 2000. Prior to that time, Ms.
Barpoulis served as Vice President, Trading Operations for USGen Power
Services, L.P., a predecessor to PG&E Energy Trading, from June 1996 to May
1998 and held various positions at U.S. Generating Company from July 1991 to
June 1996.
G. Brent Stanley has been our Senior Vice President, Human Resources since
July 2000 and has been a member of our board of directors since March 2001. He
has also served as Senior Vice President, Human Resources of PG&E Corporation
since January 1997. He was Vice President of Human Resources of Pacific Gas and
Electric Company, one of our affiliates, from February 1996 to January 1997. He
previously was Senior Vice President of Human Resources for The Gap Inc.
(retail clothing) from August 1992 to November 1994 and served in executive
human resources positions with Burlington Air Express, Inc. from May 1989 to
August 1992 and Marriott Corporation from March 1980 to May 1989.
Peter A. Darbee has been a member of our board of directors since September
1999. He has been Senior Vice President, Chief Financial Officer, and Treasurer
of PG&E Corporation since January 1999. Prior to January 1999, Mr. Darbee
served as Vice President and Chief Financial Officer of Advance Fibre
Communications, Inc. (telecommunications manufacturer of digital loop carrier
systems) from June 1997 through January 1999. Prior to that, Mr. Darbee was
Vice President, Chief Financial Officer, and Controller of Pacific Bell from
May 1994 through June 1997.
Bruce R. Worthington has been a member of our board of directors since
January 1999. He has been Senior Vice President and General Counsel of PG&E
Corporation since February 1997. Prior to that, Mr. Worthington was Senior Vice
President and General Counsel of Pacific Gas and Electric Company, one of our
affiliates, from May 1995 to February 1997. Mr. Worthington joined the law
department of Pacific Gas and Electric Company in June 1974.
Andrew L. Stidd has been a member of our board of directors since February
2001 and serves as our "independent director." He is a co-founder of Global
Securitization Services, LLC (owner and manager of special purpose funding
vehicles), and has 13 years experience in the securitization industry. From
December 1996 to the present, Mr. Stidd has been President of Global
Securitization Services, LLC. Between April 1987 and December 1996, Mr. Stidd
was Vice President, Chief Operating Officer of Lord Securities Corporation.
Prior to joining Lord Securities in 1987, Mr. Stidd was a manager in the
Controller's Department of Goldman Sachs & Co. from 1979 to 1987.
Board Structure and Compensation
Our four directors who also are our employees or employees of PG&E
Corporation receive no extra compensation for serving as directors or committee
members. We pay our other director an annual retainer of $2,500. We also
reimburse all directors for their reasonable expenses incurred in attending our
board and committee meetings and for other activities they undertake on our
behalf or for our benefit.
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Compensation Committee Interlocks and Insider Participation
None of our executive officers has served as a member of a compensation
committee (or if no committee performs that function, the board of directors)
of any other entity that has an executive officer serving as a member of our
board of directors.
Security Ownership of Management
We are an indirect wholly owned subsidiary of PG&E Corporation.
The following table provides information as of June 15, 2001 as to the
beneficial ownership of PG&E Corporation common stock by each director and each
executive officer named in the summary compensation table on the following
page, and by all of them and any other executive officers as a group. The
number of shares shown for each person (and the total number of shares shown
for all of them) constitutes less than 1% of the outstanding shares of PG&E
Corporation common stock.
Number of Shares
Name of Beneficial Owner Beneficially Owned(1)(2)
------------------------ ------------------------
Thomas G. Boren................................... 27,222
P. Chrisman Iribe................................. 132,720
Thomas B. King.................................... 59,175
Lyn Maddox........................................ 214,233
Sarah M. Barpoulis................................ 26,638
Peter A. Darbee................................... 35,552
Bruce R. Worthington.............................. 192,108
G. Brent Stanley.................................. 68,701
Andrew L. Stidd................................... --
All directors and executive officers as a group
(12 persons)..................................... 820,169
- --------
(1) Includes any shares held in the name of the spouse, minor children or other
relatives sharing the home of the director or executive officer and, in the
case of executive officers, includes shares of PG&E Corporation common
stock held in defined contribution retirement plans maintained by PG&E
Corporation and its subsidiaries. Except as indicated, the directors and
executive officers have sole voting power and investment power over the
shares shown. Voting power includes the power to direct the voting of the
shares held and investment power includes the power to direct the
disposition of the shares held. Of the 192,108 shares beneficially owned by
Mr. Worthington and all directors and executive officers as a group, 3,291
shares are subject to shared voting and investment power.
(2) Includes shares of PG&E Corporation common stock which the directors and
executive officers have the right to acquire within 60 days of June 15,
2001 through the exercise of vested stock options granted under the PG&E
Corporation Stock Option Plan, as follows: Mr. Boren: 11,718 shares; Mr.
Iribe: 114,234 shares; Mr. King: 50,001 shares; Mr. Maddox: 213,035 shares;
Ms. Barpoulis: 25,534 shares; Mr. Worthington: 172,100 shares; Mr. Stanley:
68,701 shares; and all directors and executive officers as a group, 712,824
shares. The directors and executive officers have neither voting power nor
investment power over the shares shown unless and until such shares are
purchased through the exercise of the options.
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Compensation of Executive Officers
The following table summarizes the principal components of compensation paid
to our chief executive officer and our four other most highly compensated
executive officers by PG&E Corporation or its subsidiaries during 2000.
Summary Compensation Table
Annual Compensation Long Term Compensation
---------------------------------- ------------------------------------
Awards Payouts
--------------------- --------------
Other Annual Securities Underlying Long-Term All Other
Name and Principal Salary Compensation Options/ SARs Incentive Plan Compensation
Position ($) Bonus ($)(1) ($)(2) (# of shares) Payouts ($) ($)(3)
------------------ -------- ------------ ------------ --------------------- -------------- ------------
Thomas G. Boren......... $630,000 $441,790 $ 50,478 212,600 -- $ 543,571
President and Chief
Executive Officer
P. Chrisman Iribe....... $400,000 $300,000 -- 122,700 -- $ 40,000
President and Chief
Operating Officer,
East Region
Thomas B. King.......... $400,000 $300,000 $ 49,343 122,700 -- $1,598,631
President and Chief
Operating Officer,
West Region
Lyn Maddox.............. $400,000 $300,000 $224,718 110,400 -- $ 617,472
President and Chief
Operating Officer,
Trading
Sarah M. Barpoulis...... $210,000 $252,000 -- 30,100 -- $ 21,000
Senior Vice President,
Commercial Operations,
Trading
- --------
(1) Represents payments received or deferred for achievement of corporate and
organizational objectives in 2000 under the PG&E Corporation Short-Term
Incentive Plan.
(2) Amounts reported consist of (i) reportable officer benefit allowances, (ii)
payments of related taxes, and (iii) dividend equivalent payments on
performance units under PG&E Corporation's Performance Unit Plan.
(3) Amounts reported for 2000 consist of: (i) contributions to defined
contribution retirement plans (Mr. Iribe $17,000, Mr. King $17,000, Mr.
Maddox $17,000 and Ms. Barpoulis $17,000), (ii) contributions received or
deferred under excess benefit arrangements associated with defined
contribution retirement plans (Mr. Boren $5,906, Mr. Iribe $23,000, Mr.
King $23,000, Mr. Maddox $23,000 and Ms. Barpoulis $4,000), (iii) above-
market interest on deferred compensation, and (iv) relocation allowances
and other one-time payments, including one-time payments made pursuant to
employment arrangements and credited to deferred compensation accounts (Mr.
Boren $537,665, Mr. King $1,558,631 and Mr. Maddox $577,472).
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Grants of PG&E Corporation Options in 2000
The following table shows all grants in 2000 of options to acquire PG&E
Corporation common stock made to the executive officers listed in the summary
compensation table.
PG&E Corporation Option Grants In 2000
Percent of Total
Number of Options/SARs
Securities Granted to PG&E
Underlying Corporation Exercise Grant Date
Options/SAR Employees in or Base Expiration Present
Name Granted(1) 2000 Price(2) Date(3) Value(4)
- ---- ----------- ---------------- -------- ---------- ----------
Thomas G. Boren.... 212,600 2.09% $19.8125 1/04/2010 $693,076
P. Chrisman Iribe.. 122,700 1.21% $19.8125 1/04/2010 $400,002
Thomas B. King..... 122,700 1.21% $19.8125 1/04/2010 $400,002
Lyn Maddox......... 110,400 1.09% $19.8125 1/04/2010 $359,904
Sarah M.
Barpoulis......... 30,100 0.03% $19.8125 1/04/2010 $174,580
- --------
(1) All options granted to executive officers in 2000 are exercisable as
follows: one-third of the options may be exercised on or after the second
anniversary of the grant date, two-thirds on or after the third
anniversary, and 100 percent on or after the fourth anniversary, provided
that options will vest immediately upon the occurrence of certain events.
No options were accompanied by tandem dividend equivalents.
(2) The exercise price is equal to the closing price of PG&E Corporation common
stock on the grant date.
(3) All PG&E Corporation options granted to executive officers in 2000 expire
in 10 years and one day from the grant date, subject to earlier expiration
if the officer's employment with us, PG&E Corporation, or one of our or
PG&E Corporation's subsidiaries terminates.
(4) Estimated present values are based on the Black-Scholes Model, a
mathematical formula used to value options traded on stock exchanges. The
Black-Scholes Model considers a number of factors, including the expected
volatility and dividend rate of the stock, interest rates, and the time of
exercise of the option. The following assumptions were used in applying the
Black-Scholes Model to the PG&E Corporation option grants shown in the
table above: volatility of 20.19%, risk free rate of return of 6.10%,
dividend yield of $1.20 (the annual dividend rate on PG&E Corporation
common stock on the grant date), and an exercise date five years after the
grant date. The ultimate value of the options will depend on the future
market price of PG&E Corporation common stock, which cannot be forecasted
with reasonable accuracy. The estimated grant date present value for the
options shown in the table was $3.26 per share.
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Aggregate PG&E Corporation Option/SAR Exercises in 2000 and Year-End Option/SAR
Values
The following table summarizes exercises in 2000 of PG&E Corporation stock
options and tandem stock appreciation rights (granted in prior years) by the
executive officers listed in the summary compensation table, as well as the
number and value of all unexercised PG&E Corporation options held by those
executive officers at the end of 2000.
Aggregate PG&E Corporation Option/SAR Exercises in 2000 and Year-End Values
Number of Securities
Shares Underlying Unexercised Value of Unexercised In-
Acquired Options/SARs at December the-Money Options/SARS at
on Value 31, 2000 December 31, 2000($)(1)
Exercise Realized Exercisable/Unexercisable Exercisable/Unexercisable
Name (#) ($) (#)/($) (#)/($)
- ---- -------- -------- ------------------------- -------------------------
Thomas G. Boren......... 0 0 0/374,318 0/40,595
P. Chrisman Iribe....... 0 0 46,867/277,933 0/23,006
Thomas B. King.......... 0 0 16,667/256,033 0/23,006
Lyn Maddox.............. 0 0 110,901/305,899 0/20,700
Sarah M. Barpoulis...... 0 0 4,500/95,400 0/6,900
- --------
(1) Based on the difference between the option exercise price (without
reduction for the amount of accrued dividend equivalents, if any) and a
fair market value of $20.00, which was the closing price of PG&E
Corporation common stock on December 29, 2000.
PG&E Corporation Long-Term Incentive Plan Compensation
The following table summarizes long-term incentive awards made in 2000 to
the executive officers listed in the summary compensation table. These awards
were made in accordance with the PG&E Corporation's Performance Unit Plan and
Executive Stock Ownership Program.
Long Term Incentive Plan Awards in 2000
Awards
---------------------
Performance
or Other Estimated Future Payouts Under Non-
Shares, Period Stock Price-Based Plans(3)
Units, or Until -----------------------------------
Other Maturation Threshold Target Maximum
Name Rights or Payout (#)(3) (#)(3) (#)(3)
---- --------- ----------- --------- ------------ ------------
Thomas G. Boren...... 17,700(1) 3 years 0 units 17,700 units 35,400 units
9,814(2)
P. Chrisman Iribe.... 12,250(1) 3 years 0 units 12,250 units 24,500 units
6,047(2)
Thomas B. King....... 12,250(1) 3 years 0 units 12,250 units 24,500 units
856(2)
Lyn Maddox........... 10,350(1) 3 years 0 units 10,350 units 20,700 units
3,351(2)
Sarah M. Barpoulis... 3,425(1) 3 years 0 units 3,425 units 6,850 units
- --------
(1) Represents performance units granted under the PG&E Corporation Performance
Unit Plan. The units vest one-third in each of the three years following
the grant date and are earned over the vesting period based on PG&E
Corporation's three-year cumulative total shareholder return (dividends
plus stock price appreciation) as compared with that achieved by a 12-
company comparator group. This performance target may be adjusted during
the vesting period, in the sole discretion of PG&E Corporation's Nominating
and Compensation Committee, to reflect extraordinary events beyond
management's control. Each time a cash dividend is paid on PG&E Corporation
common stock, an amount equal to the cash dividend per share
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multiplied by the number of units held by a recipient will be accrued on
behalf of the recipient and, at the end of the year, the amount of accrued
dividend equivalents will be increased or decreased by the same percentage
used to increase or decrease the recipient's number of vested performance
units for the year.
(2) Represents common stock equivalents called Special Incentive Stock
Ownership Premiums (SISOPs) earned under the PG&E Corporation Executive
Stock Ownership Program. SISOPs are earned by eligible officers who achieve
and maintain minimum PG&E Corporation common stock ownership levels as set
by PG&E Corporation's Nominating and Compensation Committee. All of the
officers listed in the summary compensation table are eligible officers.
Each SISOP represents a share of PG&E Corporation common stock, which vests
at the end of three years. Units can be forfeited prior to vesting if an
eligible officer fails to maintain his or her minimum stock ownership
level. Upon retirement or termination, vested SISOPs are distributed in the
form of an equivalent number of shares of PG&E Corporation common stock.
(3) Payments are determined by multiplying the number of units earned in a
given year by the average market price of PG&E Corporation common stock for
the 30 calendar day period before the end of the year.
Employment Contracts/Arrangements
Thomas G. Boren's employment letter entitles him to receive salary, other
cash and equity awards as described elsewhere in this prospectus, and other
standard employee benefits. Mr. Boren's participation in the supplemental
defined benefit executive retirement plan includes recognition of credited
years with his former employer, Southern Company, although benefits will be
reduced by benefits payable from Southern Company's plan, excluding special
enhancements payable as part of his separation from Southern Company. Under his
employment letter, Mr. Boren was entitled to receive $1,000,000 in three annual
installments, upon satisfaction of annual general business goals. Mr. Boren's
last installment is payable December 31, 2001, upon satisfaction of the 2001
business goals. If Mr. Boren terminates his employment with us or PG&E
Corporation or its other subsidiaries before December 31, 2001, the payment
will be forfeited. Mr. Boren also is eligible to receive a mortgage subsidy
equal to $26,667 per $100,000 of loan value, limited to a loan amount of
$1,500,000 through July 2004, with a maximum subsidy of $400,000 ($80,000 per
year). Mr. Boren also will be compensated for the loss of mortgage tax
deduction in excess of the $1,000,000 maximum allowed by law, up to the stated
maximum mortgage loan amount of $1,500,000.
Thomas B. King's employment letter entitles him to receive salary, other
cash and equity awards as described elsewhere in this prospectus, and other
standard employee benefits. In connection with his relocation to Bethesda,
Maryland, Mr. King received a one-time payment of $150,000 net of taxes, and a
one-time taxable payment of $75,000. If Mr. King resigns from his position
prior to December 31, 2004 (and is not then an employee of us or PG&E
Corporation or its other affiliates), he will be required to repay the gross
amount of such payments. Mr. King also received (1) a moving allowance equal to
one month's pay; (2) reimbursement for travel expenses incurred in finding a
principal residence in the Bethesda area, and for the reasonable cost of
temporary housing; (3) reimbursement of closing costs incurred in the sale of
his prior residence and the purchase of a new residence; (4) indemnification
for loss suffered on the sale of his prior residence; and (5) reimbursement of
certain losses and expenses incurred in placing his children in comparable
schools in the Bethesda area. Mr. King also is entitled to receive a mortgage
subsidy of $3,500 per month, payable for four years, commencing with the first
mortgage payment for his new residence. If Mr. King resigns from employment
with us, PG&E Corporation or one of its other subsidiaries or affiliates before
December 31, 2004, he will be required to repay all amounts provided under the
temporary mortgage subsidy.
Lyn E. Maddox's employment letter entitles him to receive salary, other cash
and equity awards described elsewhere in this prospectus, and other standard
employee benefits. In connection with his relocation to Bethesda, Maryland, Mr.
Maddox received a one-time payment of $250,000, net of taxes, and a one-time
taxable payment of $75,000. If Mr. Maddox resigns from his position before
December 31, 2004 (and is not then an employee of us, PG&E Corporation or its
other affiliates), he will be required to repay the gross amount of such
payments. Mr. Maddox also received (1) a moving allowance equal to one month's
pay;
97
(2) reimbursement for travel expenses incurred in finding a principal residence
in the Bethesda area, and for the reasonable cost of temporary housing; (3)
reimbursement of closing costs incurred in the sale of his prior residence and
the purchase of a new residence; (4) indemnification for loss suffered on the
sale of his prior residence; and (5) reimbursement of certain losses and
expenses incurred in placing his children in comparable schools in the Bethesda
area. Mr. Maddox also is entitled to receive a mortgage subsidy of $3,500 per
month, payable for four years, commencing with the first mortgage payment for
his new residence. If Mr. Maddox resigns from employment with us, PG&E
Corporation or one of its other subsidiaries or affiliates before December 31,
2004, he will be required to repay all amounts provided under the temporary
mortgage subsidy.
Termination of Employment and Change in Control Provisions
The PG&E Corporation Officer Severance Policy, which covers most officers of
PG&E Corporation and its subsidiaries, including the executive officers listed
in the summary compensation table, provides benefits if a covered officer is
terminated without cause. In most situations, benefits under the policy include
(i) a lump sum payment of one and one-half or two times annual base salary and
target PG&E Corporation Short-Term Incentive Plan award (the applicable
severance multiple being dependent on an officer's level), (ii) continued
vesting of equity-based awards for 18 months or two years after termination
(depending on the applicable severance multiple), (iii) accelerated vesting of
up to two-thirds of the common stock equivalents awarded under the PG&E
Corporation Executive Stock Ownership Program (depending on an officer's
level), and (iv) payment of health care insurance premiums for 18 months or two
years after termination (depending on the applicable severance multiple).
Instead of all or part of the lump sum payment, a terminated officer who is
covered by PG&E Corporation's Supplemental Executive Retirement Plan can elect
additional years of service and/or age for purposes of calculating pension
benefits. Alternative benefits apply upon actual or constructive termination
following a change in control or potential change in control of PG&E
Corporation. According to the policy, a "change in control" of PG&E Corporation
occurs upon (A) the acquisition of 20% or more of PG&E Corporation's
outstanding voting securities by a single entity or person, (B) a change in the
directors who constitute a majority of PG&E Corporation's board of directors
over a two-year period, unless the new directors were nominated by at least
two-thirds of PG&E Corporation's board of directors who were directors at the
beginning of the two-year period, or (C) approval by PG&E Corporation's
shareholders of certain corporate transactions. Constructive termination
includes certain changes to a covered officer's responsibilities. In the event
of a change in control or potential change in control, the policy provides for
a lump sum payment of the sum of (w) unpaid base salary earned through the
termination date, (x) target PG&E Corporation Short-Term Incentive Plan award
calculated for the fiscal year in which termination occurs, or the PG&E
Corporation Target Bonus, (y) any accrued but unpaid vacation pay and (z) three
times the sum of such Target Bonus and the officer's annual base salary in
effect immediately before either the date of termination or the change in
control, whichever base salary is greater. Change in control termination
benefits also include reimbursement of excise taxes levied upon the severance
benefit under Internal Revenue Code Section 4999.
The PG&E Corporation Long-Term Incentive Program, or LTIP, permits PG&E
Corporation to grant various types of stock-based incentive awards, including
awards granted under the PG&E Corporation Stock Option Plan and the PG&E
Corporation Performance Unit Plan. The PG&E Corporation LTIP and the component
plans provide that, upon a change in control of PG&E Corporation, (1) any time
periods relating to the exercise or realization of any incentive award
(including common stock equivalents awarded under the PG&E Corporation
Executive Stock Ownership Program) will be accelerated so that such award may
be exercised or realized in full immediately upon the change in control, (2)
all shares of restricted stock will immediately cease to be forfeitable, and
(3) all conditions relating to the realization of any stock-based award will
terminate immediately. Under the PG&E Corporation LTIP, a "change in control"
will be deemed to have occurred if any of the following occurs: (1) any
"person" (as that term is used in Sections 13(d) and 14(d)(2) of the Exchange
Act, but excluding any benefit plan for employees or any trustee, agent, or
other fiduciary for any such plan acting in such person's capacity as such
fiduciary), directly or indirectly, becomes the beneficial owner of securities
of PG&E Corporation representing 20% or more of the combined voting power of
PG&E Corporation's then outstanding securities, (2) during any two consecutive
years, individuals who at the
98
beginning of such a period constitute PG&E Corporation's board of directors
cease for any reason to constitute at least a majority of the board of
directors, unless the election, or the nomination for election by the
shareholders of PG&E Corporation, of each new director was approved by a vote
of at least two-thirds of the PG&E Corporation directors then still in office
who were directors at the beginning of the period, or (3) the shareholders of
PG&E Corporation shall have approved (i) any consolidation or merger of PG&E
Corporation other than a merger or consolidation that would result in the
voting securities of PG&E Corporation outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by being converted
into voting securities of the surviving entity or any parent of such surviving
entity) at least 70% of the combined voting power of PG&E Corporation, such
surviving entity, or the parent of such surviving entity outstanding
immediately after the merger or consolidation, (ii) any sale, lease, exchange,
or other transfer (in one transaction or a series of related transactions) of
all or substantially all of the assets of PG&E Corporation, or (iii) any plan
or proposal for the liquidation or dissolution of PG&E Corporation. For this
purpose, "combined voting power" means the combined voting power of the then-
outstanding voting securities of PG&E Corporation or the other relevant entity.
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RELATIONSHIP WITH PG&E CORPORATION AND RELATED TRANSACTIONS
Intercompany Relationships
We have arrangements with PG&E Corporation under which PG&E Corporation and
certain of its subsidiaries provide the following services to us: accounting,
legal, information technology, insurance, tax, human resources and benefits
administration and certain external affairs, including public relations. In
addition to these services, PG&E Corporation has made certain facilities
available to us. We reimburse PG&E Corporation at cost for these services and
facilities based on use and other allocation factors, and we also reimburse
PG&E Corporation for a portion of PG&E Corporation's overhead. Such costs
amounted to approximately $17 million in 1998, $31 million in 1999 and $43
million in 2000. In addition, we bill PG&E Corporation for certain shared
costs, which amounted to $0.3 million in 1999 and $0.8 million in 2000.
The amounts above do not include amounts paid to Pacific Gas and Electric
Company from which we receive (and to which we provide) limited corporate
support services. In 1998, 1999 and 2000, these total charges were $1.3
million, $5.5 million and $0.9 million. California Public Utilities Commission
regulations limit our ability to share certain types of services and
information with Pacific Gas and Electric Company. In addition, PG&E
Corporation's new credit agreement, which is described below, includes a
covenant that generally restricts certain intercompany transactions to those
made on arm's-length terms.
We are included in the consolidated tax return of PG&E Corporation. Through
our tax-sharing arrangement with PG&E Corporation, we have recognized tax
expense or benefit based upon our share of consolidated income or loss through
an allocation of income taxes from PG&E Corporation which allowed us to utilize
the tax benefits we generated so long as they could be used on a consolidated
basis. Beginning with the 2001 calendar year, we expect to pay to PG&E
Corporation the amount of income taxes that we would be liable for if we filed
our own consolidated combined or unitary return separate from PG&E Corporation,
subject to certain consolidated adjustments.
In addition, in the recent past Pacific Gas and Electric Company has been
GTN's largest customer and, during 1998, 1999 and 2000 and for the six months
ended June 30, 2001, accounted for $49 million, $47 million, $46 million and
$18 million, respectively, of the revenues generated by our GTN pipeline. In
addition, our energy trading operations also purchases from and sells to
Pacific Gas and Electric Company energy commodities, primarily natural gas, and
general corporate business items. In 1998, 1999 and 2000 and for the six months
ended June 30, 2001, our energy trading operations had energy commodity sales
of approximately $0.8 million, $30 million, $136 million and $123 million,
respectively, to Pacific Gas and Electric Company and energy commodity
purchases of $0.7 million, $7 million, $12 million and $3 million,
respectively. We have also engaged in transactions with Pacific Gas and
Electric Company involving products and services that are the subject of
tariffs filed with the CPUC or FERC. For example, our La Paloma generating
facility has agreed to execute an interconnection agreement with Pacific Gas
and Electric Company.
Loans, Capital Commitments and Guarantees
Periodically we and our subsidiaries have borrowed funds from, or loaned
money to, PG&E Corporation for specific transactions or other corporate
purposes. At June 30, 2001, we had a net outstanding loan balance payable to
PG&E Corporation of $355 million, including net amounts payable of $309 million
related to Attala Power Corporation, net amounts payable of $121 million in the
form of promissory notes to PG&E Corporation related primarily to past funding
of generating asset development and acquisition, and a note receivable of
$75 million related to GTN. In addition, until recently, funds from our
operations were managed through net investments or borrowing in a pooled cash
management arrangement with PG&E Corporation.
PG&E Corporation also has provided us with collateral for a range of
contractual commitments. With respect to our generating facilities, this
collateral has included agreements to infuse equity into specific projects when
these projects begin operations or when we purchase a project that we have
leased. In addition,
100
PG&E Corporation has provided guarantees of our obligations under several long-
term tolling arrangements and as collateral for our commitments under various
energy trading contracts entered into by our energy trading operations. PG&E
Corporation also provided guarantees to support several letter of credit
facilities issued by our energy trading operations to provide short-term
collateral to counterparties. As of December 31, 1999 and 2000, PG&E
Corporation had issued $793 million and $2.4 billion, respectively, in these
types of instruments.
As of August 20, 2001, except for $16 million of guarantees of various
energy trading master contracts (for which PG&E Corporation's total exposure
was approximately $320,000), we had replaced all of PG&E Corporation's equity
infusion agreements and guarantees with our own equity infusion agreements,
guarantees or other forms of security. Under its new $1 billion credit
agreement, which is described below, PG&E Corporation was required to obtain
its release from these equity infusion agreements and to reduce its exposure
under energy trading guarantees to no more than $50 million by July 2, 2001.
Our inability to replace these guarantees in accordance with PG&E Corporation's
term loans would have been a default under those loans which could have
resulted in acceleration of those loans and foreclosure by the lenders on the
pledge of our capital stock or the membership interests in the LLC.
We do not intend to lend to or borrow from PG&E Corporation in the future
nor do we expect to receive any future capital contributions or guarantees from
PG&E Corporation (either directly or indirectly).
Ringfencing Transaction
In December 2000, and during the first quarter of 2001, we undertook a
corporate restructuring, known as a "ringfencing" transaction. The ringfencing
involved the creation or use of entities as intermediate owners between PG&E
Corporation and us, between us and certain of our subsidiaries and between
certain of our subsidiaries and other subsidiaries. These ringfencing entities
are: the LLC, which owns our capital stock; GTN Holdings LLC which owns the
capital stock of GTN; and PG&E Energy Trading Holdings, LLC, which owns the
capital stock of PG&E Energy Trading Holdings Corporation, which owns the
equity of our energy trading subsidiaries.
The goal of the ringfencing was to obtain or maintain investment grade
credit ratings for us and certain of our subsidiaries, irrespective of the
credit rating of our parent. We applied for FERC approval of the interposing of
the LLC between PG&E Corporation and us which constituted part of the
ringfencing. FERC issued a letter order granting approval on January 12, 2001.
Thereafter untimely motions to intervene, requests for rehearing, and requests
to vacate that order were filed with FERC, each of which was denied by FERC on
February 21, 2001. Requests for rehearing of the February 21 order were then
filed. On April 6, 2001, FERC issued an order the effect of which permits FERC
additional time for its consideration of the various petitions for rehearing.
Our organizational documents and those of the "ringfencing" entities were
modified to provide for the creation of an "independent" member of the board of
directors or board of control of such entity. In furtherance of the rating
agency criteria, each entity's and our board of directors or board of control,
including the independent director, must unanimously approve certain
corporation matters, including the following:
. a consolidation or merger with any entity;
. the transfer of 75% or more of our or the affected entity's assets;
. the institution or consent to institution of a bankruptcy, insolvency, or
similar proceeding or action; or
. the declaration or payment of dividends or similar distributions.
In addition, if a dividend or similar distribution is to be paid or an
intercompany loan is to be made, the payor must have a specified investment
grade credit rating or meet a 2.25 to 1.00 consolidated interest coverage ratio
and, in certain instances, a 0.70 to 1.00 consolidated leverage ratio.
Moreover, the "independent member" of the board of directors or board of
control, as the case may be, must confirm compliance with one or the
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other of these criteria prior to the making of such dividend, similar
distribution or intercompany loan to any owner or affiliate.
PG&E Corporation's Financing
On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds of two term loans under a credit agreement with
General Electric Capital Corporation and Lehman Commercial Paper, Inc., an
affiliate of Lehman Brothers.
The loans will mature on March 2, 2003 (which date may be extended at the
option of PG&E Corporation for up to one year), or earlier, if our shares were
to be distributed to PG&E Corporation's shareholders. As required by the credit
agreement, PG&E Corporation has given the lenders a security interest in all of
the outstanding membership interests in the LLC. In addition, the LLC has given
the lenders a security interest in all of our outstanding capital stock.
Under the credit agreement, PG&E Corporation has covenanted that we and our
subsidiaries will make investments and capital expenditures, incur
indebtedness, sell assets and operate our businesses only to the extent such
activities are consistent with the business plan we submitted to the lenders
(and which we generally describe in the "Business" section of this prospectus)
or the activities comply with certain other negotiated exceptions. The credit
agreement also restricts our ability to pay dividends to PG&E Corporation and
engage in certain affiliate transactions, requiring them to be made on arm's-
length terms, again with certain negotiated exceptions, including the ability
to consummate certain intercompany transactions among PG&E Corporation, us and
our principal subsidiaries. Because we are not a party to the credit agreement
nor bound by its terms, our violations of any of the covenants set forth in the
credit agreement would not result in a cause of action against us or our
subsidiaries under the credit agreement; however, they would result in a
default by PG&E Corporation which could give the lenders the right to foreclose
on our capital stock or the membership interests in the LLC.
In addition, PG&E Corporation may be required to make prepayments of its
term loans upon the occurrence of certain activities relating to us and our
subsidiaries if the proceeds we or any of our subsidiaries receive from the
issuance of indebtedness (including the notes), the issuance or sale of any
equity (except for certain cash proceeds from an initial public offering),
asset sales or casualty insurance, condemnation awards or other recoveries are
not reinvested in our businesses (provided the reinvestment is within the scope
of the business plan delivered to the lenders), used to pay indebtedness or
(except for casualty, condemnation awards or other recoveries) retained as
cash. If we effect an initial public offering of our common stock, PG&E
Corporation is required to reduce the outstanding balance of the term loans to
no more than $500 million. Should PG&E Corporation fail to make such mandatory
prepayments, a default under the credit agreement will occur. A default will
also occur if Moody's and Standard & Poor's downgrade our debt below Baa3 and
BBB-, respectively, or if our fair market value falls below twice the aggregate
amount of PG&E Corporation's term loans, among other things.
Further, as required by the credit agreement, the LLC has granted to
affiliates of the lenders an option that entitles these affiliates to purchase
up to 3% of our common stock at an exercise price of $1.00 based on the
following schedule:
Percentages
of Shares
Subject to
Option
-----------
Loans outstanding for:
Less than six months........................................... 2.0%
Six to eighteen months......................................... 2.5%
Greater than eighteen months................................... 3.0%
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The option becomes exercisable on the date of full repayment of the term
loans or earlier if we were to make an initial public offering of our common
stock. We have the right to call the option in cash at a purchase price equal
to the fair market value of the underlying common stock, which right is
exercisable at any time following the repayment of the term loans. If an
initial public offering has not occurred, the holders of the option have the
right to require the LLC or PG&E Corporation to repurchase the option at a
purchase price equal to the fair market value of the underlying shares, which
right is exercisable at any time after the earlier of full repayment of the
term loans or 45 days before expiration of the option. The option will expire
45 days after the maturity of the term loans.
CPUC Proceedings Involving PG&E Corporation
On April 3, 2001, the California Public Utilities Commission issued an order
instituting an investigation into whether the California investor-owned
utilities and their holding companies, including Pacific Gas and Electric
Company and PG&E Corporation, have complied with past CPUC decisions, rules and
orders authorizing their holding company formations and/or governing affiliate
transactions, as well as applicable statutes. We are not a party to this
proceeding. The order states that the CPUC will investigate:
. the utilities' transfer of money to their holding companies since
deregulation of the electric industry commenced, including during times
when their utility subsidiaries were experiencing financial difficulties;
. whether the holding companies failed to financially assist the utilities
when needed;
. the transfer by the holding companies of assets to unregulated
subsidiaries, including capital contributions made by the holding
companies to such subsidiaries; and
. holding companies' actions to "ringfence" their unregulated subsidiaries.
The CPUC also will determine whether additional rules, conditions or changes
are needed to adequately protect ratepayers and the public from dangers of
abuse stemming from the holding company structure. The CPUC will investigate
whether it should modify, change or add conditions to the holding company
decisions, make further changes to the holding company structure, alter the
standards under which the CPUC determines whether to authorize the formation of
holding companies, otherwise modify the decisions, or recommend statutory
changes to the California Legislature. As a result of the investigation, the
CPUC has stated that it may impose sanctions (including penalties), prospective
rules, or conditions, as appropriate. The prospective rules may include changes
or additions to reporting or approval requirements regarding (1) changes in the
structure of the holding company system, such as ringfencing, (2) the
contribution or transfer of funds or other assets from the holding company to
its unregulated subsidiaries, and (3) restrictions on the holding company's
assumption of debt for purposes other than strengthening the requested utility
subsidiary.
On June 6, 2001, in response to motions filed by the affected holding
companies (including PG&E Corporation) to dismiss the investigation against
them for lack of subject matter jurisdiction, a CPUC administrative law judge
issued for comment a draft decision denying the motions. A revised draft
decision, reaching the same conclusion, was issued on July 12, 2001. The
revised draft decision concludes, among other matters, that "regulatory
doctrine allows the Commission to ignore corporate form and reach the assets
and conduct of all entities within the system--and the prerequisites to common-
law veil piercing need not be met." On July 19, 2001, CPUC Commissioner Henry
Duque issued an alternate draft decision granting the motions to dismiss. The
drafts are currently scheduled to be before the CPUC for decision on August 23,
2001. We are not a party to this investigatory proceeding. We cannot predict
whether, when or in what form a decision will be adopted, or what direct or
indirect effects any subsequent action taken by the CPUC in such proceeding or
in any other action or proceeding, in reliance on the principles articulated in
this revised draft decision and in other applicable authority, may have on us
and our ability to meet our obligations under the notes.
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Attorney General's Petition for Review and Revocation of PG&E Corporation's
Exemption from the Public Utility Holding Company Act
On July 5, 2001, the California Attorney General filed a petition asking the
SEC, under its Rule 6, to revoke in whole or in part PG&E Corporation's
exemption from registration under PUHCA. The primary argument made in the
petition is that PG&E Corporation's exemption from registration, pursuant to
Section 3(a)(1) of PUHCA, should be revoked on the basis that PG&E
Corporation's investments and activities outside of the State of California
have made the company interstate in character and that it no longer qualifies
for the Section 3(a)(1) intrastate exemption. The support for this argument
provided in the petition is the fact that PG&E Corporation has invested in a
number of ventures and activities located outside of California and that these
investments, the petition asserts, cause PG&E Corporation to violate the
requirements of its exemption. The petition also asserts that Pacific Gas and
Electric Company has made certain inappropriate distributions and transfers to
PG&E Corporation.
Under Rule 6, only the SEC itself can institute a proceeding to terminate an
exemption, a power that has been rarely used by the SEC. There is nothing in
PUHCA or the SEC rules requiring the SEC to act upon such a motion or petition
by a third party. As a result, there is no deadline by which PG&E Corporation
must respond to the petition.
On August 7, 2001, PG&E Corporation filed a response to the Attorney
General's position with the SEC. We believe the Attorney General's filing is
based upon an incorrect analysis of the relevant standards of PUHCA,
particularly Section 3(a)(1). We believe it mischaracterizes the basis upon
which Section 3(a)(1) exemptions are granted and raises no material issues of
law or fact that would appear to compel the SEC to take any actions.
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DESCRIPTION OF THE NOTES
General
We will issue the exchange notes under an indenture between us and
Wilmington Trust Company, as trustee. Upon the issuance of the exchange notes
and the effectiveness of a registration statement with respect to the notes,
the indenture will be subject to and governed by the Trust Indenture Act of
1939.
In this "Description of the Notes," references to "we," "our," "ours" and
"us" refer only to PG&E National Energy Group, Inc. and not to any of our
direct or indirect subsidiaries or affiliates. Furthermore, in this
"Description of the Notes," "notes" refers to exchange notes and original
notes. The following description is a summary of the material provisions of the
indenture. It does not restate that agreement in its entirety. We urge you to
read the indenture because it, and not this description, defines your rights as
holders of the notes. We will provide copies at no cost upon request.
Brief Description of the Notes
The notes:
. are our unsecured senior obligations;
. rank equally with all of our other existing and future senior unsecured
indebtedness;
. are senior to all of our future subordinated indebtedness;
. rank junior to all of our secured indebtedness; and
. rank junior to all indebtedness and other liabilities of our
subsidiaries.
The indenture contains no restrictions on the amount of additional unsecured
indebtedness which may be incurred by us or our subsidiaries. In addition, the
indenture permits each of our subsidiaries to incur significant additional
amounts of secured indebtedness.
Because we are a holding company, our rights and the rights of our
creditors, including holders of the notes, in respect of claims on the assets
of each of our subsidiaries upon any liquidation or administration are
structurally subordinated to, and therefore will be subject to the prior claims
of, each such subsidiary's preferred stockholders and creditors (including
trade creditors of and holders of debt issued by such subsidiary). At June 30,
2001, our consolidated direct and indirect subsidiaries had total indebtedness
and preferred stock of approximately $2.0 billion, all of which would be
effectively senior to the notes. Our obligations under the notes will not be
guaranteed by any of our subsidiaries.
Our ability to pay interest on the notes is dependent upon our receipt of
dividends and other distributions from our direct and indirect subsidiaries. We
believe that such payments, which will be funded by cash flows generated
through the operations of our subsidiaries, will be sufficient to enable us to
meet all of our obligations as they become due, including our obligations under
the notes. The availability of distributions from our subsidiaries is subject
to the satisfaction of various covenants and conditions contained in the
applicable subsidiaries' existing and future financing documents and other
agreements governing projects in which they invest. In addition, the
subsidiaries that own our natural gas transmission and energy trading
operations are subject to certain "ringfencing" provisions that, among other
things, restrict their ability to pay dividends to us.
Maturity and Interest
The notes will mature on May 16, 2011. We may, without the consent of the
holders, issue additional notes with the same terms and with the same CUSIP
numbers as the notes.
Interest on the notes will accrue at the rate of 10.375% per annum from May
22, 2001, or from the most recent interest payment date to which interest on
the original notes has been paid or provided for. We will make
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each interest payment semi-annually on May 15 and November 15 of each year,
commencing November 15, 2001, to the holders of record at the close of business
on the preceding May 1 and November 1, respectively, until the relevant
principal amount has been paid or made available for payment. Interest on the
notes will be computed on the basis of a 360-day year consisting of twelve 30-
day months.
Methods of Receiving Payments on the Notes
All payments on the notes will be made at the office or agency of the paying
agent and registrar in Wilmington, Delaware unless we elect to make interest
payments by check mailed to the holders at their address set forth in the
register of holders. A holder owning at least $50 million of notes may elect to
receive all principal, premium, if any, and interest payments on the notes by
wire transfer in accordance with the written wire transfer instructions
provided to us by that holder.
Paying Agent and Registrar for the Notes
The trustee will initially act as paying agent and registrar. We may change
the paying agent or registrar without prior notice to the holders of the notes,
and we or any of our subsidiaries may act as paying agent or registrar;
provided that we will at all times maintain one or more paying agents that have
an office in Wilmington, Delaware.
Transfer and Exchange
A holder may transfer or exchange notes in accordance with the indenture.
The registrar and the trustee may require a holder, among other things, to
furnish appropriate endorsements and transfer documents, and we may require a
holder to pay any taxes and fees required by law or permitted by the indenture.
We are not required to transfer or exchange any notes selected for redemption.
Also, we are not required to transfer or exchange any notes for a period of 15
days before a selection of notes to be redeemed is made.
The registered holder of a note will be treated as the owner of it for all
purposes. See "--Book-Entry; Delivery and Form" below.
Redemption
We may redeem the notes at any time, in whole or in part, at a redemption
price equal to:
. the greater of:
(1) 100% of the principal amount of the notes being redeemed;
or
(2) the sum of the present values of the remaining scheduled payments of
principal and interest on the notes being redeemed discounted to the
date of redemption on a semiannual basis (assuming a 360-day year
consisting of twelve 30-day months) at a rate equal to the Treasury
Yield (as defined below) plus 50 basis points,
. plus, in either case, accrued and unpaid interest, if any, on the
principal amount of the notes being redeemed to the redemption date.
If the redemption date is not a scheduled interest payment date with respect
to that note, the amount of the next succeeding scheduled interest payment on
that note will be reduced by the amount of interest accrued on that note to the
redemption date.
If fewer than all the notes are to be redeemed, selection of notes of a
series for redemption will be made by the trustee in any manner the trustee
deems fair and appropriate. We will give notice to The Depository Trust
Company, or DTC, and holders of definitive notes at least 30 days (but not more
than 60 days) before we
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redeem the notes. If we redeem only some of the notes, DTC's practice is to
choose by lot the amount to be redeemed from the notes held by each of its
participating institutions. DTC will give notice to these participants, and
these participants will give notice to any "street name" holders of any
indirect interests in the notes according to arrangements among them. These
notices may be subject to statutory or regulatory requirements. We will not be
responsible for giving notice of a redemption of the notes to anyone other than
DTC and holders of definitive notes.
Unless we default in payment of the redemption price, from and after the
redemption date the notes or portions of them called for redemption will cease
to bear interest, and the holders of the notes will have no right in respect to
such notes except the right to receive the redemption price for them.
Discussion of Redemption Provisions
Under the procedures set forth above, the redemption price payable upon the
optional redemption at any time of a note is determined by calculating the
present value at that time of each remaining payment of principal of or
interest on the note and then totaling those present values. If the sum of
those present values is equal to or less than 100% of the principal amount of
the note, the redemption price of the note will be 100% of its principal amount
(redemption at par). If the sum of the present values is greater than 100% of
the principal amount of the note, the redemption price of the note will be that
greater amount (redemption at a premium), plus accrued and unpaid interest, if
any, of the principal amount of the note being redeemed to the redemption date.
In no event may a note be redeemed optionally at less than 100% of its
principal amount.
The present value at any time of a payment of principal of or interest on a
note is calculated by applying to the payment the discount rate applicable to
the note. The discount rate applicable at any time to payment of principal of
or interest on a note equals the equivalent yield to maturity at that time of a
fixed rate United States treasury security having a maturity comparable to the
remaining term to maturity of the note plus 50 basis points, such yield being
calculated on the basis of the interest rate borne by that United States
treasury security and the price at that time of that treasury security. While
the coupon borne by a United States treasury security is fixed, the price of
that treasury security tends to vary with interest rate levels prevailing from
time to time. In general, if at a particular time the prevailing level of
interest rates is higher than the level of interest rates prevailing at the
time the relevant United States treasury security was issued, the price of that
treasury security will be lower than its issue price. Conversely, if at a
particular time the prevailing level of interest rates is lower than the level
of interest rates prevailing at the time the relevant United States treasury
security was issued, the price of that treasury security will be higher than
its issue price.
As a result, an increase or a decrease in the then prevailing level of
interest rates above or below the level of interest rates prevailing at the
time of issue of a United States treasury security will generally result in an
increase or a decrease, respectively, in the yield to maturity of that security
and, therefore, in the discount rate used to determine the present value of a
payment of principal of or interest on a note. An increase or a decrease in the
discount rate will result in a decrease or an increase, respectively, of the
present value of a payment of principal of or interest on a note. In other
words, the redemption price varies inversely with the prevailing levels of
interest rates. As noted above, however, if the sum of the present values of
the remaining payments of principal of and interest on a note proposed to be
redeemed is less than its principal amount, that note may only be redeemed at
par.
Certain Definitions
"Comparable Treasury Issue" means the United States Treasury security
selected by Lehman Brothers Inc. or an affiliate as having a maturity
comparable to the remaining term of the notes that would be utilized, at the
time of selection and in accordance with customary financial practice, in
pricing new issues of corporate debt securities of comparable maturity to the
remaining term of the notes.
"Comparable Treasury Price" means the average of three Reference Treasury
Dealer Quotations obtained by the trustee in respect of the notes to be
redeemed on the applicable redemption date.
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"Reference Treasury Dealer Quotation" 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 a Reference Treasury Dealer at 3:30 p.m., New York
City time, on the third business day preceding the redemption date.
"Reference Treasury Dealers" means Lehman Brothers Inc. (so long as it
continues to be a primary U.S. Government securities dealer) and any two other
primary U.S. Government securities dealers chosen by us. If Lehman Brothers
Inc. ceases to be a primary U.S. Government securities dealer, we will appoint
in its place another nationally recognized investment banking firm that is a
primary U.S. Government securities dealer.
"Treasury Yield" means, with respect to any redemption date, an annual rate
equal to the semiannual 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
the redemption date. The semiannual equivalent yield to maturity will be
computed as of the third business day immediately preceding the redemption
date.
Certain Covenants
Restrictions on Liens
We have agreed not to pledge, mortgage, hypothecate or permit to exist any
mortgage, pledge or other lien upon any property at any time directly owned by
us or any of our subsidiaries to secure any indebtedness for money borrowed
which is incurred, issued or assumed by us or to secure any guarantees issued
by us of indebtedness for money borrowed (collectively, "Indebtedness") without
providing for the notes to be equally and ratably secured with any and all such
Indebtedness and with any other Indebtedness similarly entitled to be equally
and ratably secured; provided, however, that this agreement will not apply to,
or prevent the creation or existence of:
. mortgages, pledges, liens, charges, security interests or encumbrances
(collectively, "Liens") on our assets existing at the original date of
issuance of notes and, to the extent we or any of our subsidiaries
consolidate with, or merge into, another entity, Liens on the assets of
such entity in existence on the date of such consolidation or merger and
securing debt of such entity, provided that such debt and Liens were not
created or incurred in anticipation of such consolidation or merger;
. purchase money or construction financing Liens that do not exceed the
cost or value of the property being purchased or constructed;
. Liens granted in connection with extending, renewing, replacing or
refinancing in whole or in part the Indebtedness (including increasing
the principal amount of such Indebtedness, provided that any such Lien
is limited to all or part of the same property or assets (plus
improvements, accessions, proceeds or dividends or distributions in
respect thereof) that secured (or, under the written arrangements under
which the original Lien arose, could secure) the Indebtedness being
extended, renewed, replaced or refinanced) secured by Liens described in
the two preceding bullet points above; and
. other Liens not to exceed 10% of our Consolidated Net Tangible Assets,
provided that:
(a) neither we nor our subsidiaries shall be permitted to create or to
permit to exist any liens to secure our Indebtedness in reliance upon
this item until the earlier to occur of:
(x) the first date on or after May 22, 2003 on which the Notes are
rated at least Baa3 by Moody's and BBB- by Standard & Poor's, and
(y) the date on which Moody's rates the notes Baa1 or higher and
Standard & Poor's rates the notes BBB+ or higher; and
(b) notwithstanding the restriction in clause (a) above, we and our
subsidiaries shall be permitted to create and permit to exist Liens
in reliance upon this item to secure Indebtedness not to exceed $250
million in the aggregate.
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This covenant will not restrict the ability of our subsidiaries and
affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage,
pledge or lien upon their assets to secure any indebtedness incurred by them,
in connection with project financings or otherwise.
"Consolidated Net Tangible Assets" means, as of the date of determination,
the total amount of all of our assets, determined on a consolidated basis in
accordance with generally accepted accounting principles as of such date, after
deducting therefrom:
. our consolidated current liabilities, determined in accordance with
generally accepted accounting principles; and
. our assets that are properly classified as intangible assets in
accordance with generally accepted accounting principles.
If we propose to pledge, mortgage or hypothecate any property at any time
directly owned by us or any of our subsidiaries to secure any Indebtedness,
other than as permitted by the second previous paragraph, we have agreed to
give prior written notice thereof to the trustee, who will give notice to the
holders of notes, and we will further agree, prior to or simultaneously with
such pledge, mortgage or hypothecation, effectively to secure all the notes
equally and ratably with such Indebtedness.
Restrictions on Asset Sales
Except for a sale of all or substantially all of our assets as described in
"--Merger, Consolidation, Sale, Lease or Conveyance," and other than assets we
are required to sell to conform with governmental regulations, we may not, and
we will cause our subsidiaries not to, sell or otherwise dispose of any assets
(other than short-term, readily marketable investments purchased for cash
management purposes with funds not representing the proceeds of other asset
sales) if, on a pro forma basis, the aggregate net book value of all such sales
during the most recent 12-month period would exceed 10% of our Consolidated Net
Tangible Assets (as defined above) computed as of the end of the most recent
quarter preceding such sale; provided, however, that any such sales shall be
disregarded for purposes of this 10% limitation if the proceeds are invested in
assets in our business, in the energy trading, energy services, power
generation, electric transmission or gas transmission and storage businesses or
in similar or related lines of business; and provided further, that we may sell
or otherwise dispose of assets in excess of this 10% limitation if we retain
the proceeds from such sales or dispositions, which are not reinvested as
provided above, as cash or cash equivalents or if we use the proceeds from such
sales to purchase and retire notes or Indebtedness ranking equal in right of
payment to the notes or indebtedness of our subsidiaries.
Merger, Consolidation, Sale, Lease or Conveyance
We have agreed not to merge or consolidate with or into any other person and
not to sell, lease or otherwise transfer, in a single transaction or in a
series of transactions, all or substantially all of our assets to any person,
unless:
. the continuing or successor corporation (whether us or another
corporation) or the person that acquires all or substantially all of our
assets is a corporation organized and existing under the laws of the
United States or a State thereof or the District of Columbia and
expressly assumes all our obligations under the notes and the indenture
or assumes such obligations as a matter of law;
. immediately after giving effect to such merger, consolidation, sale,
lease or other transfer there is no default or Event of Default under
the indenture;
. if, as a result of the merger, consolidation, sale, lease or conveyance,
any or all of our property would become the subject of a lien that would
not be permitted by the indenture, we secure the notes equally and
ratably with the obligations secured by that lien; and
. we deliver or cause to be delivered to the trustee an officers'
certificate and opinion of counsel each stating that the merger,
consolidation, sale, lease or conveyance comply with the indenture.
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The meaning of the term "all or substantially all of the assets" has not
been definitely established and is likely to be interpreted by reference to
applicable state law if and at the time the issue arises and will be dependent
on the facts and circumstances existing at the time.
Reporting Obligations
The indenture provides that whether or not we are required to do so by the
rules and regulations of the SEC, so long as any notes are outstanding, we will
furnish to each of the holders of notes:
. all quarterly and annual financial information that would be required to
be contained in a filing with the SEC on Forms 10-Q and 10-K (commencing
with the Form 10-Q for the quarter ending June 30, 2001) if we were
required to file such financial information, including a "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" that describes our financial condition and results of
operations and any consolidated subsidiaries and, with respect to the
annual information only, reports thereon by our independent public
accountants (which shall be firm(s) of established national reputation);
and
. all information that would be required to be filed with the SEC on Form
8-K if we were required to file such reports.
For so long as any notes remain outstanding, we shall furnish to the holders
and to securities analysts and prospective investors, upon their request, the
information required to be delivered pursuant to Rule 144A(d)(4) under the
Securities Act.
Additional Covenants
Subject to certain exceptions and qualifications, we have agreed in the
indenture to do, among other things, the following:
. deliver to the trustee annual officers' certificates with respect to our
compliance with our obligations under the indenture;
. maintain our corporate existence, subject to the provisions described
above relating to mergers and consolidations; and
. pay our taxes when due, except when we are contesting such taxes in good
faith.
Events of Default
Each of the following is an "Event of Default" under the indenture:
(1) our failure to pay any interest on any note when due, which failure
continues for 30 days;
(2) our failure to pay principal or premium when due;
(3) our failure to perform any other covenant in the notes or the
indenture, which failure continues for 90 days after the trustee or the
holders of at least 25% in aggregate principal amount of the notes gives us
written notice of our failure to perform;
(4) an event of default occurring under any instrument of ours under
which there may be issued, or by which there may be secured or evidenced,
any Indebtedness in excess of $50 million, which event of default 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);
(5) one or more non-appealable final judgments, decrees or orders of
any court, tribunal, arbitrator, administrative or other governmental body
or similar entity for the payment of money aggregating more than $50
million shall be rendered against us (excluding the amount thereof covered
by insurance) and
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shall remain undischarged, unvacated and unstayed for more than 90 days,
except while being contested in good faith by appropriate proceedings; and
(6) certain events of bankruptcy, insolvency or reorganization in
respect of us.
If any Event of Default (other than an Event of Default due to certain
events of bankruptcy, insolvency or reorganization) has occurred and is
continuing, either the trustee or the holders of not less than 25% in principal
amount of the notes outstanding under the indenture may declare the principal
of all notes under the indenture and interest accrued thereon to be due and
payable immediately. If an Event of Default specified in clause (6) above
occurs with respect to us, the principal, premium, if any, and accrued interest
on the notes shall be due and payable, without further action or notice on the
part of the trustee or any holder.
Upon becoming aware of any Event of Default, we will deliver to the trustee
a statement specifying such Event of Default.
The holders of at least a majority in principal amount of the notes may, by
written notice to the trustee, waive an existing default or an Event of Default
with respect to the notes and rescind an acceleration with respect to the notes
and its consequences if:
. all existing Events of Default applicable to the notes other than the
nonpayment of the principal, premium, if any, and interest on the notes
that have become due solely by that declaration of acceleration, have
been cured or waived; and
. the rescission would not conflict with any judgment or decree of a court
of competent jurisdiction.
The trustee is entitled, subject to the duty of the trustee during a default
to act with the required standard of care, to be indemnified by the holders of
notes before proceeding to exercise any right or power under the indenture at
the request of such holders. Subject to such provisions in the indenture for
the indemnification of the trustee and certain other limitations, the holders
of a majority in principal amount of the notes then outstanding may direct the
time, method and place of conducting any proceeding for any remedy available to
the trustee or exercising any trust or power conferred on the trustee.
No holder of notes may pursue any remedy under the indenture or the notes
(except actions for payment of overdue principal or interest) unless:
. such holder previously has given the trustee written notice of a
continuing Event of Default;
. the holders of not less than 25% in principal amount of the notes then
outstanding have requested the trustee to pursue such remedy;
. the holder or holders have offered the trustee satisfactory indemnity;
. the trustee has not complied within 60 days of the request; and
. the trustee has not received direction inconsistent with such written
request from the holders of a majority in principal amount of the notes
then outstanding.
Modification of the Indenture
The indenture contains provisions permitting us and the trustee, with the
consent of the holders of at least a majority in aggregate principal amount of
notes then outstanding, to modify or amend the indenture, including the
provisions relating to the rights of the holders of the notes. However, no such
modification or amendment may, without the consent of the holder of each of the
outstanding notes affected thereby:
. change the stated maturity of the principal of, or interest on, any
note;
. reduce the principal amount of, reduce the rate of, or extend or change
the time of payment of interest on, any note;
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. change the place or currency of payment of principal of, or interest on,
any note;
. reduce any amount payable upon the redemption of any note;
. impair the right to institute suit for the enforcement of any payment on
or with respect to any note;
. reduce the percentage in principal amount of outstanding notes the
consent of whose holders is required for modification or amendment of
the indenture;
. reduce the percentage in principal amount of outstanding notes necessary
for waiver of compliance with certain provisions of the indenture or for
waiver of certain defaults; or
. modify such provisions with respect to modification and waiver.
The holders of at least a majority in principal amount of the outstanding
notes may waive compliance by us with certain restrictive provisions of the
indenture.
We and the trustee may, without the consent of any holder of notes, amend
the indenture and the notes to cure any ambiguity, defect or inconsistency, to
provide for assumption of our obligations to a successor, to make changes that
would provide the holders with additional benefits, to make any change that is
not inconsistent with the indenture and the notes and will not adversely affect
the interest of any holder of the notes and to comply with the requirements of
the SEC.
Defeasance and Covenant Defeasance
Defeasance
We will be deemed to have paid and will be discharged from any and all
obligations in respect of the notes on the 123rd day after we have made the
deposit referred to below, and the provisions of the indenture will cease to be
applicable with respect to the notes (except for, among other matters, certain
obligations to register the transfer of or exchange of the notes, to replace
stolen, lost or mutilated notes, to maintain paying agencies and to hold funds
for payment in trust) if:
(1) we have deposited with the trustee, in trust, money and/or certain
U.S. government obligations that will provide money in an amount
sufficient, in the opinion of a nationally recognized public accounting
firm, to pay the principal of, premium, if any, and accrued interest on the
notes at the time such payments are due in accordance with the terms of the
indenture;
(2) we have delivered to the trustee:
(a) an opinion of counsel to the effect that note holders will not
recognize income, gain or loss for federal income tax purposes as a
result of the defeasance and will be subject to federal income tax on
the same amounts and in the same manner and at the same times as would
have been the case if such deposit, defeasance and discharge had not
occurred, which opinion of counsel must be based upon a ruling of the
Internal Revenue Service to the same effect or a change in applicable
federal income tax law or related treasury regulations after the date
of the indenture; and
(b) an opinion of counsel to the effect that the defeasance trust
does not constitute an "investment company" within the meaning of the
Investment Company Act of 1940 and after the passage of 123 days
following the deposit, the trust fund will not be subject to the effect
of any applicable bankruptcy, insolvency, reorganization or similar
laws affecting creditors' rights generally; and
(3) no Event of Default, or event that after the giving of notice or
lapse of time or both would become an Event of Default, will have occurred
and be continuing on the date of such defeasance or insofar as certain
effects of bankruptcy, insolvency or reorganization in respect of us during
the period ending on the 123rd day after the date of such deposit, and such
deposit shall not result in a breach or violation of, or constitute a
default under, any other material agreement or instrument to which we are a
party or by which we are bound.
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Defeasance of Certain Covenants and Certain Events of Default
The provisions of the indenture will cease to be applicable with respect to:
. the covenants described in "--Certain Covenants" (other than those with
respect to the maintenance of our existence and those described under
the first paragraph of the caption "--Certain Covenants--Merger,
Consolidation, Sale, Lease or Conveyance");
. clause (3) in "--Events of Default" with respect to such covenants; and
. clauses (4), (5) and (6) in "--Events of Default" upon:
(1) the satisfaction of the conditions described in clauses (1),
(2)(b), and (3) of the preceding paragraph; and
(2) our delivery to the trustee of an opinion of counsel to the effect
that the holders of the notes will not recognize income, gain or loss for
federal income tax purposes as a result of such defeasance and will be
subject to federal income tax on the same amount and in the same manner and
at the same times as would have been the case if such deposit and
defeasance had not occurred.
Defeasance and Certain Other Events of Default
If we exercise our option to omit compliance with certain covenants and
provisions of the indenture as described in the immediately preceding paragraph
and the notes are declared due and payable because of the occurrence of an
Event of Default that remains applicable, the amount of money and/or U.S.
government obligations on deposit with the trustee may not be sufficient to pay
amounts due on the notes at the time of acceleration resulting from such Event
of Default. In such event, we will remain liable for such payments.
Book-Entry; Delivery and Form
General
Except as set forth below, the exchange notes will initially be issued in
the form of one or more global notes (each, a "new global note"). Each new
global note will be deposited on the date of the closing of the exchange of the
original notes for the exchange notes with, or on behalf of, DTC and will be
registered in the name of DTC or its nominee. Investors may hold their
beneficial interests in a new global note directly through DTC or indirectly
through organizations which are participants in the DTC system.
Unless and until they are exchanged in whole or in part for certificated
notes, the new global notes may not be transferred except as a whole by DTC or
its nominee.
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 Uniform Commercial Code
and a "clearing agency" registered pursuant to the provisions of Section
17A of the Exchange Act.
. DTC was created to hold securities for its participants and to
facilitate the clearance and settlement of securities transactions
between participants through electronic book-entry changes in accounts
of its participants, thereby eliminating the need for physical movement
of certificates. Participants include securities brokers and dealers,
banks, trust companies and clearing corporations and other
organizations. Indirect access to the DTC system is available to others,
including banks, brokers, dealers and trust companies that clear through
or maintain a custodial relationship with a participant, either directly
or indirectly.
Upon the issuance of the new global notes, DTC or its custodian will credit,
on its internal system, the respective principal amounts of the exchange notes
represented by the new global notes to the accounts of
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persons who have accounts with DTC. Ownership of beneficial interests in the
new global notes will be limited to persons who have accounts with DTC or
persons who hold interests through the persons who have accounts with DTC.
Persons who have accounts with DTC are referred to as "participants." Ownership
of beneficial interests in the new global notes will be shown on, and the
transfer of that ownership will be effected only through, records maintained by
DTC or its nominee, with respect to interests of participants, and the records
of participants, with respect to interests of persons other than participants.
As long as DTC or its nominee is the registered owner or holder of the new
global notes, DTC or the nominee, as the case may be, will be considered the
sole record owner or holder of the exchange notes represented by the new global
notes for all purposes under the indenture and the exchange notes. No
beneficial owners of an interest in the new global notes will be able to
transfer that interest except according to DTC's applicable procedures, in
addition to those provided for under the indenture. Owners of beneficial
interests in the new global notes will not:
. be entitled to have the exchange notes represented by the new global
notes registered in their names,
. receive or be entitled to receive physical delivery of certificated
notes in definitive form, and
. be considered to be the owners or holders of any exchange notes under
the new global notes.
Accordingly, each person owning a beneficial interest in new global notes
must rely on the procedures of DTC and, if a person is not a participant, on
the procedures of the participant through which that person owns its interests,
to exercise any right of a holder of exchange notes under the new global notes.
We understand that under existing industry practice, if an owner of a
beneficial interest in the new global notes desires to take any action that
DTC, as the holder of the new global notes, is entitled to take, DTC would
authorize the participants to take that action, and that the participants would
authorize beneficial owners owning through the participants to take that action
or would otherwise act upon the instructions of beneficial owners owning
through them.
Payments of the principal of, premium, if any, and interest on the exchange
notes represented by the new global notes will be made by us to the trustee and
from the trustee to DTC or its nominee, as the case may be, as the registered
owner of the new global notes. Neither we, the trustee, nor any paying agent
will have any responsibility or liability for any aspect of the records
relating to or payments made on account of beneficial ownership interests in
the new global notes or for maintaining, supervising or reviewing any records
relating to the beneficial ownership interests.
We expect that DTC or its nominee, upon receipt of any payment of principal
of, premium, if any, or interest on the new global notes will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial ownership interests in the principal amount of the new
global notes, as shown on the records of DTC or its nominee. We also expect
that payments by participants to owners of beneficial interests in the new
global notes held through these participants will be governed by standing
instructions and customary practices, as is now the case with securities held
for the accounts of customers registered in the names of nominees for these
customers. These payments will be the responsibility of these participants.
Transfer between participants in DTC will be effected in the ordinary way in
accordance with DTC rules. If a holder requires physical delivery of notes in
certificated form for any reason, including to sell notes to persons in states
which require the delivery of the notes or to pledge the notes, a holder must
transfer its interest in the new global notes in accordance with the normal
procedures of DTC and the procedures set forth in the indenture.
Unless and until they are exchanged in whole or in part for certificated
exchange notes in definitive form, the new global notes may not be transferred
except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or
another nominee of DTC.
DTC has advised us that DTC will take any action permitted to be taken by a
holder of notes, including the presentation of notes for exchange as described
below, only at the direction of one or more participants to
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whose account the DTC interests in the new global notes are credited. Further,
DTC will take any action permitted to be taken by a holder of notes only in
respect of that portion of the aggregate principal amount of notes as to which
the participant or participants has or have given that direction.
Although DTC has agreed to these procedures in order to facilitate transfers
of interests in the new global notes among participants of DTC, it is under no
obligation to perform these procedures, and may discontinue them at any time.
Neither we nor the trustee will have any responsibility for the performance by
DTC or its participants or indirect participants of their respective
obligations under the rules and procedures governing their operations.
Subject to specified conditions, any person having a beneficial interest in
the new global notes may, upon request to the trustee, exchange the beneficial
interest for exchange notes in the form of certificated notes. Upon any
issuance of certificated notes, the trustee is required to register the
certificated notes in the name of, and cause the same to be delivered to, the
person or persons, or the nominee of these persons. In addition, if DTC is at
any time unwilling or unable to continue as a depositary for the new global
notes, and a successor depositary is not appointed by us within 120 days, we
will issue certificated notes in exchange for the new global notes.
Registration Rights Agreement
As part of the sale of the original notes, under a registration rights
agreement, dated as of May 22, 2001, we agreed with the initial purchasers in
the offering of the original notes, for the benefit of the holders of the
original notes, to file with the SEC an exchange offer registration statement
or, if applicable, a shelf registration statement.
If any holder of an original note that is a qualified institutional buyer
notifies us prior to the 20th day following the consummation of the exchange
offer that (i) such holder was prohibited by applicable law or SEC policy from
participating in the exchange offer, (ii) that such holder may not resell the
exchange notes to the public without delivering a prospectus and that the
prospectus contained in the exchange offer registration statement is not
appropriate or available for such resale by such holder or (iii) that it is a
participating broker-dealer and holds notes acquired directly from us or one of
our affiliates, then in each case, we will (x) promptly deliver to the holders
written notice thereof and (y) at our sole expense (a) as promptly as
practicable (but in no event more than 90 days after so required or requested
pursuant to the registration rights agreement), file a shelf registration
statement covering resales of those notes (b) use our reasonable best efforts
to cause the shelf registration statement to be declared effective under the
Securities Act (but in no event more than 120 days after so required or
requested pursuant to the registration rights agreement or, if later, (300 days
after the original notes were issued) and (c) use our reasonable best efforts
to keep effective the shelf registration statement until the earlier of two
years (or, if Rule 144(k) is amended to provide a shorter restrictive period,
such shorter period) after the issuance of the notes or such time as all of the
applicable notes have been sold under the shelf registration statement. We
will, if a shelf registration statement is declared effective, provide to each
holder copies of the prospectus that is a part of the shelf registration
statement, notify each such holder when the shelf registration statement for
the notes has become effective and take any other actions as are required to
permit unrestricted resales of the notes. A holder that sells original notes
pursuant to the shelf registration statement will be required to be named as a
selling security holder in the related prospectus, to provide information
related thereto and to deliver that prospectus to purchasers, will be subject
to certain of the civil liability provisions under the Securities Act in
connection with the sales and will be bound by the provisions of the
registration rights agreement that are applicable to such a holder (including
certain indemnification rights and obligations). We will not have any
obligation to include in the shelf registration statement holders who do not
deliver that information to us.
If we fail to comply with certain provisions of the registration rights
agreement, as described below, then a special interest premium will become
payable in respect of the original notes.
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If any required shelf registration statement is not declared effective on or
before March 18, 2002, the special interest premium will accrue in respect of
the original notes from and including March 19, 2002 at a rate equal to 0.50%
per annum. The aggregate amount of the special interest premium in respect of
the original notes payable pursuant to the above provision will in no event
exceed 0.50% per annum and provided, further, that if the exchange offer
registration statement is not declared effective on or before March 18, 2002
and we request holders of the notes to provide the information called for by
the registration rights agreement for inclusion in the shelf registration
statement, the notes owned by holders who do not deliver such information to us
when required pursuant to the registration rights agreement will not be
entitled to any such increase in the interest rate for any day after March 18,
2002. Upon effectiveness of a shelf registration statement, after March 18,
2002, the interest rate on the original notes from the day of consummation will
be reduced to the original interest rate.
If a shelf registration statement is declared effective pursuant to the
foregoing paragraphs, and if such shelf registration statement ceases to be
continuously effective or the prospectus contained in such shelf registration
statement ceases to be usable for resales (x) at any time prior to the earlier
of two years (or if Rule 144(k) is amended to provide a shorter restrictive
period, such shorter period) after the issuance of the original notes or such
time as all of the applicable original notes have been sold under the shelf
registration statement or (y) due to corporate developments, public filings
with the SEC or similar events, or because the prospectus contains an untrue
statement of a material fact or omits to state a material fact required to be
stated therein or necessary in order to make the statements therein not
misleading, and such failure continues for more than 60 days (whether or not
consecutive and whether or not arising out of a single or multiple
circumstances) in any twelve-month period (the day, with respect to (x), or the
61st day, with respect to (y), being referred to as the "default day"), then
from the default day until the earlier of (i) the date that the shelf
registration statement and the prospectus are again deemed effective and usable
for resales, respectively, (ii) the date that is the second anniversary of the
issuance of the original notes (or, if Rule 144(k) is amended to provide a
shorter restrictive period, such shorter period), or (iii) the date as of which
all of the original notes are sold pursuant to the shelf registration
statement, the special interest premium in respect of the original notes will
accrue at a rate equal to 0.50% per annum. The aggregate amount of the special
interest premium in respect of the original notes payable pursuant to the above
provisions will in no event exceed 0.50% per annum.
If we fail to keep the shelf registration statement continuously effective
or useable for resales pursuant to the preceding paragraph, we will give the
holders notice to suspend the sale of the original notes and will extend the
relevant period referred to above during which we are required to keep
effective the shelf registration statement (or the period during which
participating broker-dealers are entitled to use the prospectus included in an
exchange offer registration statement in connection with the resale of exchange
notes) by the number of days during the period from and including the date of
the giving of such notice to and including the date when holders will have
received copies of the supplemented or amended prospectus necessary to permit
resales of the notes or to and including the date on which we have given notice
that the sale of the original notes may be resumed, as the case may be.
The registration rights agreement is governed by, and will be construed in
accordance with, the laws of the State of New York. The summary herein of
certain provisions of the registration rights agreement does not purport to be
complete and is subject to, and is qualified in its entirety by reference to,
all the provisions of the registration rights agreement, a form of which is
available upon request to us. In addition, the information set forth above
concerning certain interpretations and positions taken by the staff is not
intended to constitute legal advice, and prospective investors should consult
their own legal advisors with respect to these matters.
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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES
The following summary describes certain United States federal income tax
consequences of the purchase, ownership and disposition of the exchange notes
as of the date hereof. Except where noted, it deals only with purchasers that
acquired the original notes pursuant to the offering at the initial offering
price and who will hold the exchange notes as capital assets within the meaning
of Section 1221 of the Internal Revenue Code of 1986, as amended, or the Code,
and does not deal with specific situations, such as those of dealers in
securities or currencies, financial institutions, life insurance companies,
persons holding notes as part of a hedging or conversion transaction or a
straddle, or persons whose functional currency is not the United States dollar.
Furthermore, the discussion below is based upon the provisions of the Code,
existing and proposed United States Treasury regulations promulgated
thereunder, and current administrative rulings and judicial decisions thereon,
all of which are subject to change, possibly on a retroactive basis, so as to
result in United States federal income tax consequences different from those
discussed below.
Prospective holders should consult with their tax advisors as to the United
States federal income tax consequences of the acquisition, ownership and
disposition of notes in light of their particular circumstances, as well as the
effect of any state, local or other tax laws.
As used in this prospectus, the term "United States holder" means a
beneficial owner of a note that is (i) a citizen or resident of the United
States for United States federal income tax purposes, (ii) a corporation or
partnership (or any entity treated as a corporation or partnership for United
States federal income tax purposes) created or organized under the laws of the
United States, any state thereof or the District of Columbia, (iii) an estate
the income of which is subject to United States federal income tax without
regard to its source or (iv) a trust if (x) a court within the United States is
able to exercise primary supervision over the administration of the trust and
one or more United States persons have the authority to control all substantial
decisions of the trust or (y) the trust has a valid election in effect under
applicable United States Treasury regulations to be treated as a United States
holder. If a partnership (including any entity treated as a partnership for
United States federal income tax purposes) is a holder of the notes, the United
States federal income tax treatment of a partner in such a partnership will
generally depend on the status of the partner and the activities of the
partnership. Partners in such a partnership should consult their own tax
advisors as to the particular federal income tax consequences applicable to
them.
A "non-United States holder" is any beneficial holder of a note that is not
a United States holder.
Exchange Offer
For United States federal income tax purposes, a beneficial owner of an
original note will not recognize any taxable gain or loss on the exchange of
the original notes for exchange notes under the exchange offer, and a
beneficial owner's tax basis and holding period in the exchange notes will be
the same as in the original notes.
United States Holders
Stated interest on an exchange note generally will be taxable to a United
States holder as ordinary income at the time it accrues or is received in
accordance with the United States holder's method of accounting for United
States federal income tax purposes.
Upon the sale, exchange, redemption, retirement or other disposition of an
exchange note, a United States holder generally will recognize gain or loss
equal to the difference between the amount realized upon the sale, exchange,
redemption, retirement or other disposition (not including amounts attributable
to accrued but unpaid interest, which will be taxable as ordinary income) and
such United States holder's adjusted tax basis in the exchange note. A United
States holder's adjusted tax basis in an exchange note will, in general, be the
United States holder's adjusted basis in the original note exchanged for the
exchange note, less any principal payments
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received by such holder. Such gain or loss will generally be capital gain or
loss. Capital gain recognized by an individual investor upon a disposition of
an exchange note that has been held for more than 12 months will generally be
subject to a maximum tax rate of 20% or, in the case of an exchange note that
has been held for 12 months or less, will be subject to tax at ordinary income
tax rates. A United States holder's holding period for an exchange note will
include the holding period of the original note exchanged for the exchange
note.
Non-United States Holders
Under present United States federal income tax law, subject to the
discussion of backup withholding and information reporting below:
(a) payments of interest on the exchange notes to any non-United States
holder will not be subject to United States federal income, branch profits
or withholding tax provided that:
. the non-United States holder does not actually or constructively own 10%
or more of the total combined voting power of all classes of our stock
entitled to vote;
. the non-United States holder is not a bank receiving interest on an
extension of credit pursuant to a loan agreement entered into in the
ordinary course of its trade or business;
. the non-United States holder is not a controlled foreign corporation that
is related to us (directly or indirectly) through stock ownership;
. such interest payments are not effectively connected with a United States
trade or business;
. the non-United States holder is not a foreign tax exempt organization or
foreign private foundation for United States federal income tax purposes;
and
. certain certification requirements are met. Such certification will be
satisfied if the beneficial owner of the exchange note certifies on IRS
Form W-8BEN or a substantially similar substitute form, under penalties
of perjury, that it is not a United States person and provides its name
and address, and (x) such beneficial owner files such form with the
withholding agent or (y) in the case of an exchange note held through a
foreign partnership or intermediary, the beneficial owner and the foreign
partnership or intermediary satisfy certification requirements of
applicable United States Treasury regulations; and
(b) a non-United States holder will not be subject to United States
federal income or branch profits tax on gain realized on the sale,
exchange, redemption, or retirement or other disposition of an exchange
note, unless (i) the gain is effectively connected with a trade or business
carried on by such holder within the United States or, if a treaty applies
(and the holder complies with applicable certification and other
requirements to claim treaty benefits), is generally attributable to a
United States permanent establishment maintained by the holder, or (ii) the
holder is an individual who is present in the United States for 183 days or
more in the taxable year of disposition and certain other requirements are
met.
An exchange note held by an individual who at the time of death is not a
citizen or resident of the United States will not be subject to United States
federal estate tax with respect to a note as a result of such individual's
death, provided that (i) the individual does not actually or constructively own
10% or more of the total combined voting power of all classes of our stock
entitled to vote and (ii) the interest accrued on the exchange note was not
effectively connected with the conduct of a United States trade or business.
Backup Withholding and Information Reporting
In general, payments of interest and the proceeds of the sale, exchange,
redemption, retirement or other disposition of the exchange notes payable by a
United States paying agent or other United States intermediary will be subject
to information reporting. In addition, backup withholding will generally apply
to these payments if (i) in the case of a United States holder, the holder
fails to provide an accurate taxpayer identification number, or fails to
certify that such holder is not subject to backup withholding or fails to
report all interest and
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dividends required to be shown on its United States federal income tax returns,
or (ii) in the case of a non-United States holder, the holder fails to provide
the certification on IRS Form W-8BEN described above or otherwise does not
provide evidence of exempt status. Certain United States holders (including,
among others, corporations) and non-United States holders that comply with
certain certification requirements are not subject to backup withholding. The
rate of backup withholding will be 30.5% for the remainder of 2001, 30% in 2002
and 2003, 29% in 2004 and 2005, 28% in 2006 through 2010, and 31% thereafter.
Any amount paid as backup withholding will be creditable against the holder's
United States federal income tax liability provided that the required
information is timely furnished to the IRS. Holders of exchange notes should
consult their tax advisors as to their qualification for exemption from backup
withholding and the procedure for obtaining such an exemption.
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC in no action letters issued
to third parties, we believe that you may freely transfer exchange notes issued
in the exchange offer if:
. you acquire the exchange notes in the ordinary course of your business,
and
. you are not engaged in, and do not intend to engage in, and have no
arrangement or understanding with any person to participate in, a
distribution of exchange notes.
We believe that you may not transfer exchange notes issued in the exchange
offer in exchange for the original notes if you are:
. our "affiliate" within the meaning of Rule 405 under the Securities Act,
. a broker-dealer that acquired original notes directly from us, or
. a broker-dealer that acquired original notes as a result of market-making
activities or other trading activities without compliance with the
registration and prospectus delivery provisions of the Securities Act.
If you wish to exchange your original notes for exchange notes in the
exchange offer, you will be required to make representations to us as described
in "The Exchange Offer--Procedures for Tendering" and in the letter of
transmittal.
Each broker-dealer that receives exchange notes for its own account under
the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of such exchange notes. Broker-dealers may use this
prospectus for resales of exchange notes received in exchange for original
notes where the original notes were acquired as a result of market-making
activities or other trading activities.
We will not receive any proceeds from any sale of exchange notes by broker-
dealers. Broker-dealers may sell exchange notes received for their own account
under the exchange offer in transactions:
. in the over-the-counter market,
. in negotiated transactions,
. through the writing of options on the exchange notes, or
. a combination of such methods of resale.
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The prices at which these sales occur may be:
. at market prices prevailing at the time of resale,
. at prices related to such prevailing market prices, or
. at negotiated prices.
Broker-dealers may make any such resale directly to purchasers or to or
through brokers or dealers who may receive compensation in the form of
commissions or concessions from any such broker-dealer or the purchasers of any
such exchange notes. Any broker-dealer that receives exchange notes for its own
account under the exchange offer and any broker or dealer that participates in
a distribution of such exchange notes may be deemed to be an "underwriter"
within the meaning of the Securities Act. Any profit on any such resale of
exchange 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 admit that it is an
"underwriter" within the meaning of the Securities Act.
Furthermore, any broker-dealer that acquired any of its original notes
directly from us:
. may not rely on the applicable interpretation of the staff of the SEC's
position contained in Exxon Capital Holdings Corp., SEC no-action letter
(available April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action
letter (available June 5, 1991) and Shearman & Sterling, SEC no-action
letter (available July 2, 1983); and
. must also be named as a selling noteholder in connection with the
registration and prospectus delivery requirements of the Securities Act
relating to any resale transaction.
For a period of 210 days from the date the registration statement related to
this prospectus is declared effective, we will send a reasonable number of
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker-dealer that requests such documents in the letter of
transmittal. We have agreed to pay all expenses incident to the exchange offer
other than commissions or concessions of any broker-dealers and will indemnify
the holders of the notes (including any broker-dealers) against some
liabilities, including liabilities under the Securities Act.
LEGAL MATTERS
The legality of the exchange notes and certain other legal matters will be
passed on for us by Orrick, Herrington & Sutcliffe LLP, San Francisco,
California.
EXPERTS
The consolidated financial statements as of December 31, 1999 and 2000, and
for the years ended December 31, 1999 and 2000, included in this prospectus and
the related 1999 and 2000 financial statement schedules included elsewhere in
the registration statement have been audited by Deloitte & Touche LLP,
independent auditors, as stated in their report appearing herein and elsewhere
in the registration statement (which report expresses an unqualified opinion
and includes explanatory paragraphs referring to a change in accounting for
major maintenance expenditures and the liquidity matters of an affiliated
company) and are included in reliance upon the report of such firm given upon
their authority as experts in accounting and auditing.
The consolidated financial statements for the year ended December 31, 1998
in this prospectus and elsewhere in the registration statement have been
audited by Arthur Andersen LLP, independent public accountants, as indicated in
their report (which includes an explanatory paragraph with respect to liquidity
matters of an affiliated company as discussed in Note 2 to the financial
statements) with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing.
120
AVAILABLE INFORMATION
This prospectus is part of a registration statement on Form S-4 that we
filed with the SEC. This prospectus does not contain all of the information in
the registration statement. For further information with respect to us and the
exchange notes offered by this prospectus, you should review the registration
statement. Statements in this prospectus as to the contents of any contract or
other document are not necessarily complete and, where any contract or other
document is an exhibit to the registration statement, we refer you to that
exhibit for a more complete description of the matter involved.
We are not currently subject to the informational requirements of the
Securities Exchange Act of 1934. However, upon effectiveness of the
registration statement of which this prospectus is a part, we will become
subject to the informational requirements of the Exchange Act and commence
filing annual, quarterly and current reports and other information with the
SEC. In addition, our parent, PG&E Corporation, and our subsidiary, PG&E Gas
Transmission Northwest Corporation, both file annual, quarterly and current
reports and other information with the SEC.
You may read and copy the registration statement and the reports and other
information we will file after the effective date of the registration statement
and any reports and other information that PG&E Corporation and PG&E Gas
Transmission Northwest Corporation file with the SEC at the SEC's public
reference room at 450 Fifth Street, N.W., Washington, D.C. Please call the SEC
at 1-800-SEC-0330 for further information on the public reference rooms. Our
SEC filings and those of PG&E Corporation and PG&E Gas Transmission Northwest
Corporation are also available to you free of charge at the SEC's web site at
www.sec.gov.
In addition, we have agreed that, whether or not we are required to do so by
the rules and regulations of the SEC, for so long as the original notes or the
exchange notes remain outstanding, we will furnish to each of the note holders
all quarterly and annual financial information that would be required to be
contained in a filing with the SEC on Forms 10-Q and 10-K (commencing with the
Form 10-Q for the quarter ended June 30, 2001) if we were required to file such
financial information, including a "Management's Discussion and Analysis of
Financial Condition and Results of Operations" that describes our financial
condition and results of operations and any consolidated subsidiaries and, with
respect to the annual information only, reports thereon by our independent
public accountants (which shall be firm(s) of established national reputation).
We will also furnish to each of the note holders all information that would be
required to be filed with the SEC on Form 8-K if we were required to file such
reports. We will make such reports available to prospective purchasers of the
original notes or the exchange notes, as applicable, securities analysts and
broker-dealers upon their request. We have agreed, if we are not then subject
to the periodic reporting requirements of the Exchange Act, to furnish to
holders of the notes, and any prospective purchaser of the notes, upon their
request, the information required by Rule 144A(d)(4) under the Securities Act,
until such time as the original notes are no longer "restricted securities"
within the meaning of Rule 144 under the Securities Act (assuming such notes
have not been owned by an affiliate of ours).
121
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report.............................................. F-2
Report of Independent Public Accountants.................................. F-3
Consolidated Statements of Operations--Years Ended December 31, 1998, 1999
and 2000 and Six Months Ended June 30, 2000 and 2001 (Unaudited)......... F-5
Consolidated Balance Sheets As of December 31, 1999 and 2000 and June 30,
2001 (Unaudited)......................................................... F-6
Consolidated Statements of Common Stockholder's Equity--Years Ended
December 31, 1998, 1999 and 2000......................................... F-8
Consolidated Statements of Cash Flows--Years Ended December 31, 1998, 1999
and 2000 and Six Months Ended June 30, 2000 and 2001 (Unaudited)......... F-9
Notes to Consolidated Financial Statements................................ F-10
F-1
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholder of
PG&E National Energy Group, Inc.:
We have audited the accompanying consolidated balance sheets of PG&E
National Energy Group, Inc. and Subsidiaries (the "Company") as of December 31,
2000 and 1999, and the related consolidated statements of operations, cash
flows and common stockholder's equity for the years then ended. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with the 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
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, such 2000 and 1999 consolidated financial statements present
fairly, in all material respects, the consolidated financial position of PG&E
National Energy Group, Inc. and Subsidiaries as of December 31, 2000 and 1999,
and the consolidated results of operations and cash flows for the years then
ended in conformity with accounting principles generally accepted in the United
States of America.
See Note 2 of the consolidated financial statements for discussion of the
liquidity matters of an affiliated company.
As discussed in Note 3 of the consolidated financial statements, in 1999 the
Company changed its method of accounting for major maintenance and overhauls.
/s/ DELOITTE & TOUCHE LLP
McLean, Virginia
March 16, 2001
(April 6, 2001 as to Note 2)
F-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder of
PG&E National Energy Group, Inc.:
We have audited the accompanying consolidated statement of operations of
PG&E National Energy Group, Inc. and subsidiaries for the year ended December
31, 1998, and the related consolidated statements common stockholder's equity,
and cash flows for the year then ended. 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 audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the results of operations of PG&E National Energy
Group, Inc. and subsidiaries for the year ended December 31, 1998, and the
results of their cash flows for the year then ended, in conformity with
accounting principles generally accepted in the United States.
See Note 2 of the consolidated financial statements for discussion of
liquidity matters of the Company's Parent and an affiliated company.
/s/ ARTHUR ANDERSEN LLP
Vienna, Virginia
December 16, 2000
(except with respect to the matter discussed
in Note 2, as to which the date is April 6, 2001)
F-3
(THIS PAGE INTENTIONALLY LEFT BLANK}
F-4
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Millions)
Six Months
Years Ended December Ended June
31, 30,
------------------------- --------------
1998 1999 2000 2000 2001
------- ------- ------- ------ ------
(unaudited)
Operating Revenues:
Generation, transportation, and
trading.......................... $10,533 $11,957 $16,930 $6,656 $6,915
Equity in earnings of affiliates.. 117 63 65 37 49
------- ------- ------- ------ ------
Total operating revenues........ 10,650 12,020 16,995 6,693 6,964
------- ------- ------- ------ ------
Operating Expenses:
Cost of commodity sales and fuel.. 9,874 10,982 15,667 6,077 6,321
Operations, maintenance, and
management....................... 395 601 716 344 273
Administrative and general........ 45 49 68 26 36
Depreciation and amortization..... 167 214 143 70 75
Impairments and write-offs........ -- 1,275 -- -- --
Other operating expenses.......... 7 5 10 (16) 49
------- ------- ------- ------ ------
Total operating expenses........ 10,488 13,126 16,604 6,501 6,754
------- ------- ------- ------ ------
Operating Income (Loss)............. 162 (1,106) 391 192 210
Other Income (Expenses):
Interest income................... 45 75 80 34 49
Interest expense.................. (156) (162) (155) (78) (58)
Other income (expense)--net....... (7) 52 6 (9) 6
------- ------- ------- ------ ------
Income (Loss) From Continuing
Operations Before Income Taxes..... 44 (1,141) 322 139 207
Income tax expense (benefit)...... 41 (351) 130 55 82
------- ------- ------- ------ ------
Income (loss) from continuing
operations....................... 3 (790) 192 84 125
------- ------- ------- ------ ------
Discontinued Operations:
Loss from operations of PG&E
Energy Services--net of
applicable income tax benefit of
$36 million and $39 million,
respectively..................... (57) (47) -- -- --
Loss on disposal of PG&E Energy
Services--net of applicable
income tax benefit of $36 million
and $36 million, respectively.... -- (58) (40) -- --
------- ------- ------- ------ ------
Net Income (Loss) Before Cumulative
Effect of a Change in Accounting
Principle.......................... (54) (895) 152 84 125
Cumulative Effect of a Change in
Accounting Principle--
Net of applicable income taxes of
$8 million....................... -- 12 -- -- --
------- ------- ------- ------ ------
Net Income (Loss)................. $ (54) $ (883) $ 152 $ 84 $ 125
======= ======= ======= ====== ======
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions)
December 31,
--------------- June 30,
1999 2000 2001
------ ------- -----------
(unaudited)
ASSETS
------
Current Assets:
Cash and cash equivalents....................... $ 228 $ 738 $ 801
Restricted cash................................. 81 53 102
Accounts receivable, trade (net of allowance for
uncollectibles of $19 million, $19 million and
$49 million, respectively)..................... 1,047 2,470 1,151
Other receivables............................... -- 159 207
Note receivable from Parent..................... -- 75 --
Inventory....................................... 133 112 113
Price risk management assets--current........... 389 2,039 2,656
Assets related to discontinued operations--
current........................................ 114 -- --
Prepaid expenses, deposits, and other........... 133 474 235
------ ------- -------
Total current assets.......................... 2,125 6,120 5,265
------ ------- -------
Property, Plant, and Equipment:
Property, plant, and equipment in service....... 4,607 3,747 4,335
Accumulated depreciation........................ (770) (757) (821)
------ ------- -------
3,837 2,990 3,514
Construction work in progress..................... 217 650 350
------ ------- -------
Total property, plant, and equipment--net..... 4,054 3,640 3,864
------ ------- -------
Other Noncurrent Assets:
Long-term receivables........................... 611 536 496
Long-term receivables from Parent............... -- -- 203
Investments in unconsolidated affiliates........ 530 417 420
Goodwill, net of accumulated amortization of $14
million, $25 million and $28 million,
respectively................................... 105 100 96
Price risk management assets--noncurrent........ 319 2,026 1,045
Assets related to discontinued operations--
noncurrent..................................... 83 -- --
Other........................................... 239 267 568
------ ------- -------
Total other noncurrent assets................. 1,887 3,346 2,828
------ ------- -------
Total Assets.................................. $8,066 $13,106 $11,957
====== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS--(Continued)
(In Millions)
December 31,
--------------- June 30,
1999 2000 2001
------ ------- -----------
(unaudited)
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
Current Liabilities:
Short-term borrowings........................... $ 524 $ 519 $ 445
Long-term debt--current portion................. 93 17 10
Obligations due related parties and affiliates.. 33 309 309
Accounts payable:
Trade......................................... 853 2,170 853
Related parties............................... 73 156 33
Accrued expenses................................ 152 281 342
Price risk management liabilities--current...... 323 1,999 2,545
Out-of-market contractual obligations--current
portion........................................ 163 141 129
Liabilities related to discontinued operations--
current........................................ 61 -- --
Other........................................... 121 241 104
------ ------- -------
Total current liabilities................... 2,396 5,833 4,770
------ ------- -------
Noncurrent Liabilities:
Long-term debt.................................. 1,805 1,390 2,104
Deferred income taxes........................... 650 792 720
Price risk management liabilities--noncurrent... 207 1,867 1,028
Out-of-market contractual obligations--
noncurrent..................................... 941 800 739
Liabilities related to discontinued operations--
noncurrent..................................... 10 -- --
Long-term advances from Parent.................. 44 -- 118
Other noncurrent liabilities and deferred
credit......................................... 131 45 38
------ ------- -------
Total noncurrent liabilities................ 3,788 4,894 4,747
------ ------- -------
Minority Interest................................. 21 18 19
Commitments and Contingencies..................... -- -- --
Preferred Stock of Subsidiary..................... 57 57 58
Common Stockholder's Equity:
Capital stock, $1.00 par value--1,000 shares
issued and outstanding......................... -- -- --
Paid-in capital................................. 2,737 3,086 3,086
Retained accumulated deficit.................... (933) (781) (656)
Accumulated other comprehensive loss............ -- (1) (67)
------ ------- -------
Total common stockholder's equity........... 1,804 2,304 2,363
------ ------- -------
Total Liabilities and Stockholder's Equity........ $8,066 $13,106 $11,957
====== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(In Millions, Except for Shares)
Accum-
Retained ulated
Earnings Other Total Compre-
(Accum- Compre- Stock- hensive
Common Paid-In ulated hensive holder's (Loss)
Shares Stock Capital Deficit) Income Equity Income
------ ------ ------- -------- ------- -------- -------
Balance, December 31,
1997................... 1,000 $ -- $2,300 $ 4 $(11) $2,293
Net loss................ -- -- -- (54) -- (54) $ (54)
Foreign currency
translation
adjustment............. -- -- -- -- 7 7 7
-----
Comprehensive (loss)
income................. -- -- -- -- -- $ (47)
=====
Capital contributions... -- -- 624 -- -- 624
Cash distributions...... -- -- (151) -- -- (151)
----- ----- ------ ----- ---- ------
Balance, December 31,
1998................... 1,000 -- 2,773 (50) (4) 2,719
Net loss................ -- -- -- (883) -- (883) $(883)
Foreign currency
translation
adjustment............. -- -- -- -- 4 4 4
-----
Comprehensive (loss)
income................. -- -- -- -- -- $(879)
=====
Capital contributions... -- -- 75 -- -- 75
Cash distributions...... -- -- (111) -- -- (111)
----- ----- ------ ----- ---- ------
Balance, December 31,
1999................... 1,000 -- 2,737 (933) -- 1,804
Net income.............. -- -- -- 152 -- 152 $ 152
Foreign currency
translation
adjustment............. -- -- -- -- (1) (1) (1)
-----
Comprehensive (loss)
income................. -- -- -- -- -- $ 151
=====
Capital contributions... -- -- 633 -- -- 633
Cash distributions...... -- -- (284) -- -- (284)
----- ----- ------ ----- ---- ------
Balance, December 31,
2000................... 1,000 $ -- $3,086 $(781) $ (1) $2,304
===== ===== ====== ===== ==== ======
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
Six Months
Years Ended Ended
December 31, June 30,
------------------------ --------------
1998 1999 2000 2000 2001
------- ------ ------- ----- -------
(unaudited)
Cash Flows From Operating Activities:
Net income (loss)................... $ (54) $ (883) $ 152 $ 84 $ 125
Adjustments to reconcile net income
(loss):
Depreciation and amortization..... 167 214 143 70 75
Deferred income taxes............. 150 (227) 161 8 (72)
Amortization of out-of-market
contractual obligation........... (65) (181) (163) (84) (73)
Other deferred credits and
noncurrent liabilities........... 54 (77) (89) 40 (5)
(Gain) loss on impairment or sale
of assets........................ 11 1,256 (16) (21) --
Loss from discontinued
operations....................... 57 105 40 -- --
Equity in earnings of affiliates.. (117) (63) (65) (37) (49)
Distribution from affiliates...... 69 66 104 72 38
Cumulative effect of change in
accounting principle............. -- (12) -- -- --
Net effect of changes in working
capital assets and liabilities:
Restricted cash..................... 33 (14) 28 43 (49)
Accounts receivable--trade.......... 321 (387) (1,498) (907) 1,293
Inventories, prepaids and
deposits........................... (228) (56) (339) (310) 118
Price risk management assets and
liabilities--net................... (21) (121) (21) 62 (33)
Accounts payable and accrued
liabilities........................ (624) 276 1,446 822 (1,359)
Accounts payable--related parties... 295 (2) 83 (16) 13
Other--net.......................... 16 180 197 106 (3)
------- ------ ------- ----- -------
Net cash provided by (used in)
operating activities........... 64 74 163 (68) 19
------- ------ ------- ----- -------
Cash Flows From Investing Activities:
Capital expenditures................ (221) (150) (312) (100) (288)
Acquisition of generating assets.... (1,746) -- (311) -- (3)
Proceeds from sale--leaseback....... 479 -- -- -- --
Proceeds from sale of assets
(equity investments)............... 228 90 442 114 --
Prepayments on generating assets.... -- -- -- -- (268)
Long-term receivable................ 20 66 75 37 40
Other--net.......................... (45) (69) (38) (39) (4)
------- ------ ------- ----- -------
Net cash used in investing
activities..................... (1,285) (63) (144) 12 (523)
------- ------ ------- ----- -------
Cash Flows From Financing Activities:
Net borrowings (repayments) under
credit facilities.................. 193 231 (5) (108) (74)
Long-term debt issued............... 378 129 -- 88 259
Notes issuance, net of discount and
issuance costs..................... -- -- -- -- 974
Long-term debt matured, redeemed,
or repurchased..................... -- (269) (85) -- (592)
Advances (to) from Parent........... 44 (6) 79 (52) --
Capital contributions............... 624 75 608 203 --
Distributions....................... (151) (111) (106) (85) --
------- ------ ------- ----- -------
Net cash provided by (used in)
financing activities............. 1,088 49 491 46 567
------- ------ ------- ----- -------
Net Change in Cash and Cash
Equivalents......................... (133) 60 510 (10) 63
Cash and Cash Equivalents, Beginning
of Period........................... 301 168 228 228 738
------- ------ ------- ----- -------
Cash and Cash Equivalents, End of
Period.............................. $ 168 $ 228 $ 738 $ 218 $ 801
======= ====== ======= ===== =======
Supplemental Disclosures of Cash Flow
Information:
Cash paid for:
Interest--net of amount
capitalized...................... $ 143 $ 153 $ 148 $ 78 $ 57
Income taxes--net of refunds...... (90) (162) (12) 2 --
Supplemental Disclosures of Noncash
Investing and Financing:
Reclassification of short-term
Parent receivables to long-term.... -- -- -- -- 203
Reclassification of demand notes
payable to Parent from short-term
to long-term....................... -- -- -- -- 118
Assumption of liabilities for New
England Electric System............ 1,381 -- -- -- --
Long-term debt assumed by purchaser
from the sale of GTT............... -- -- (564) -- --
Note payable forgiven by Parent to
NEG................................ -- -- (25) -- --
Note receivable forgiven by NEG to
Parent............................. -- -- 178 (25) --
Long-term debt related to the
purchase of Attala Generating
Company............................ -- -- (159) -- (40)
Change in other comprehensive
income due to SFAS 133............. -- -- -- -- 110
Change in deferred income taxes due
to SFAS 133........................ -- -- -- -- (45)
Transfer of assets from long-term
prepaid to CIP..................... -- -- -- -- (535)
The accompanying notes are an integral part of these consolidated financial
statements.
F-9
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 1998, 1999 and 2000 and Unaudited for
the Six Months Ended June 30, 2000 and 2001
1. ORGANIZATION AND BASIS OF PRESENTATION
PG&E National Energy Group, Inc. is a wholly owned indirect subsidiary of
PG&E Corporation ("Parent"). PG&E National Energy Group, Inc. and its
subsidiaries (collectively, "NEG" or the "Company") are principally located in
the United States and Canada and are engaged in power generation and
development, wholesale energy marketing and trading, risk management, and
natural gas transmission. The Company's principal subsidiaries include PG&E
Generating Company, LLC and its subsidiaries (collectively, "Gen LLC"); PG&E
Energy Trading Holdings Corporation and its subsidiaries (collectively, "Energy
Trading" or "ET"); and PG&E Gas Transmission, Northwest Corporation and its
subsidiaries (collectively, "GTN") and PG&E Gas Transmission, Texas Corporation
and subsidiaries, and PG&E Gas Transmission Teco, Inc. and subsidiaries
(collectively "GTT"). See Note 4 for a discussion of the sale of GTT. PG&E
Energy Services Corporation ("ES"), which was discontinued in 1999, provided
retail energy services (see Note 4). NEG also has other less significant
subsidiaries.
PG&E National Energy Group, Inc. was incorporated on December 18, 1998 as a
wholly owned subsidiary of the Parent. Shortly thereafter, the Parent
contributed various subsidiaries to the NEG. The audited consolidated financial
statements of NEG as of December 31, 1999 and 2000 and for the years ended
December 31, 1998, 1999 and 2000 and the unaudited consolidated financial
statements as of June 30, 2001 and for the six months ended June 30, 2000 and
2001, have been prepared on a basis that includes the historical financial
position and results of operations of the subsidiaries that were wholly owned
or majority-owned and controlled as of December 31, 2000. For those
subsidiaries that were acquired or disposed of during the periods presented by
NEG, or by the Parent prior to or after NEG's formation, the results of
operations are included from the date of acquisition. For those subsidiaries
disposed of during the periods presented, the results of operations are
included through the date disposed.
All significant intercompany accounts and transactions have been eliminated
in consolidation. Investments in affiliates in which the Company has the
ability to exercise significant influence but not control are accounted for
using the equity method.
The accompanying consolidated balance sheet as of June 30, 2001 and
consolidated statements of operations and cash flows for the six months ended
June 30, 2000 and 2001 are unaudited. These consolidated interim financial
statements were prepared on a basis consistent with that of the audited annual
financial statements and include all adjustments necessary to present a fair
statement of the consolidated financial position and results of operations for
the interim periods. Results of operations for interim periods are not
necessarily indicative of results to be expected for a full year.
The consolidated statements of operations include all revenues and costs
directly attributable to the Company, including costs for functions and
services performed by centralized Parent organizations and directly charged to
the Company based on usage or other allocation arrangements. The results of
operations in these consolidated financial statements also include general
corporate expenses allocated by the Parent to the Company based on assumptions
that management believes are reasonable under the circumstances. However, these
allocations may not necessarily be indicative of the costs and expenses that
would have resulted if the Company had performed such services itself.
2. RELATIONSHIP WITH THE PARENT AND THE CALIFORNIA ENERGY CRISIS
For periods prior to 2001, the Parent provided financial support in the form
of direct lending activities with the Company and collateral to third parties
to support the Company's contractual commitments and daily
F-10
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
operations. Funds from operations were managed through net investments or
borrowings in a pooled cash management arrangement, and the Parent provided
credit support for trading activities through Parent guarantees and surety
bonds. Certain development and construction activities were funded in part
through Parent equity contributions or secured using instruments such as Parent
guarantees or equity commitments. As of December 31, 2000, Parent guarantees to
third parties for trading and structured tolling arrangements totaled $2.4
billion and Parent equity funding commitments for construction activities
totaled $1 billion. The Parent also assisted with financing activities through
short-term demand borrowings and long-term notes between the Parent and the
Company and Parent guarantees of certain minor credit facilities. Furthermore,
the Company, the Parent and another affiliate of the Parent share the costs of
certain administrative and general functions, as further described in Note 14.
The Parent's financial condition in the past had a direct operational and
financial impact on the Company. The Parent's credit rating affected the value
of the Parent guarantees supporting the Company's trading, development and
construction activities. The Parent experienced liquidity and credit problems
as a result of financial difficulties at another subsidiary, the California
public utility Pacific Gas and Electric Company (the "Utility"). Under the
current deregulated wholesale power purchase market scheme in California, the
Utility's wholesale power purchase costs have exceeded revenues provided by
frozen retail electric rates, resulting in undercollected purchased power costs
of approximately $6.6 billion at December 31, 2000. In January 2001, the major
credit rating agencies downgraded the Parent's credit ratings to below
investment grade entitling the Company's counterparties to demand substitute
credit support. In addition, under the Parent's equity funding commitment
agreements that supported the Company's operations and construction activities,
the downgrade and the subsequent failure by the Parent to provide an acceptable
letter of credit in the required amounts within the required time periods would
trigger the Parent's obligation to infuse the required amounts of capital.
Failure by the Parent to meet its equity commitments would have constituted a
default under these agreements. Furthermore, the Parent defaulted on certain
debt payments and suspended its quarterly dividends.
On March 2, 2001, the Parent refinanced its outstanding commercial paper and
bank borrowings with the $1 billion proceeds from two term loans (the "New
Parent Debt") borrowed under a common credit agreement with General Electric
Capital Corporation and Lehman Commercial Paper, Inc. (the "Lenders"). Standard
& Poor's subsequently removed its below-investment-grade credit rating since
the Parent no longer had rated securities outstanding. Under the New Parent
Debt agreement, the Parent has given the Lenders a security interest in the
Parent's ownership in the Company and an option to purchase 2 to 3 percent of
the shares of NEG at an exercise price of $1.00. This option becomes
exercisable upon the date of full repayment of the New Parent Debt or earlier,
if an initial public offering ("IPO") of the shares of NEG were to occur. Any
net proceeds from an IPO of NEG must first be used to reduce the outstanding
balance of the New Parent Debt to $500 million or less. Among other things, the
covenants of the New Parent Debt require that NEG maintain an investment grade
credit rating for its unsecured long-term debt.
The Parent and NEG have completed a corporate restructuring of the NEG,
known as a "ringfencing" transaction. The ringfencing complied with credit
rating agency criteria, enabling NEG, Gen LLC, GTN and ET to receive or retain
their own credit ratings, based upon their creditworthiness. The ringfencing
involved the creation or use of special purpose entities ("SPEs") as
intermediate owners between the Parent and its NEG subsidiaries. These SPEs
are: PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG;
GTN Holdings LLC, which owns 100% of the stock of GTN; and PG&E Energy Trading
Holdings LLC which owns 100% of the stock of ET. In addition, the NEG's
organizational documents were modified to include the same structural elements
as the SPEs to meet credit rating agency criteria. The SPEs require unanimous
approval of their respective boards of directors, which includes an independent
director, before they can (a) consolidate or merge with any entity, (b)
transfer substantially all of their assets to any entity, or (c) institute or
consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs
may not declare or pay
F-11
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
dividends unless the respective boards of directors have unanimously approved
such action and the company meets specified financial requirements. After the
ringfencing structure was implemented, two independent rating agencies,
Standard & Poor's and Moody's, reaffirmed investment grade ratings for GTN and
Gen LLC and issued investment grade ratings for NEG. Standard & Poor's also
issued an investment grade rating for ET.
The Company has replaced most of the Parent guarantees and other credit
enhancements with security provisions backed solely by the Company or its
subsidiaries. As of April 6, 2001, the Company had replaced or eliminated
Parent guarantees with respect to the Company's trading operations totaling
$2.2 billion with a combination of guarantees provided by the Company or its
subsidiaries and letters of credit obtained independently by the Company. As of
May 31, 2001, the Company had negotiated substitute equity commitments with
certain third parties to construction financing agreements, replacing the $1
billion of Parent guarantees and equity commitments under the construction
financing agreements.
As of December 31, 2000, Attala Power Corporation ("APC"), an indirect
wholly-owned subsidiary of the Company, had a non-recourse demand note payable
to the Parent (see Note 8) of $309 million and GTN had a note receivable from
the Parent of $75 million. In addition, as of December 31, 2000, the Company
had a net accounts payable amount of $116 million in the form of promissory
notes to the Parent related primarily to past funding of generating asset
development and acquisition and net notes payable aggregating $34 million
related to services performed by or for the Company. Furthermore, as of
December 31, 2000, the Company had recorded a $128 million account receivable
from the Parent related to the intercompany tax-sharing arrangement (see Note
3); this amount is included in prepaid expenses, deposits, and other in the
accompanying consolidated balance sheet as of December 31, 2000. The demand
note between APC and the Parent is recourse only to the assets of APC and not
to the Company. With the exception of these intercompany balances, the Company
has terminated its intercompany borrowing and cash management programs with the
Parent and settled its outstanding balances due to or from the Parent. The
Company does not intend to pursue any future financing transactions with the
Parent. Instead, management of the Company believes that it will be able to
meet its short-term obligations and fund growth and operations through retained
earnings, third-party borrowing facilities or other strategies.
On April 6, 2001, the Utility filed a voluntary petition for relief under
the provisions of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy
Court. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the Bankruptcy Court.
Management believes that the Company and its direct and indirect
subsidiaries, as described above, would not be substantively consolidated with
the Parent in any insolvency or bankruptcy proceeding involving the Parent or
the Utility.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates--The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions. These estimates and
assumptions affect the reported amounts of revenues, expenses, assets,
liabilities and disclosure of contingencies at the date of the financial
statements. Actual results could differ from these estimates.
Accounting for Price Risk Management Activities--The Company engages in
price risk management activities for both trading and non-trading purposes. Net
open positions often exist or are established due to the Company's assessment
of and response to changing market conditions. Non-trading activities are
conducted to
F-12
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
optimize and secure the return on risk capital deployed within the Company's
existing asset and contractual portfolio. Derivatives and other financial
instruments associated with trading activities in electric power, natural gas,
natural gas liquids, fuel oil and coal are accounted for using the mark-to-
market method of accounting. Under mark-to-market accounting, the Company's
trading contracts, including both physical contracts and financial instruments,
are recorded at market value, which approximates fair value. The market prices
used to value these transactions reflect management's best estimates
considering various factors including market quotes, forward price curves, time
value and volatility factors of the underlying commitments. The values are
adjusted to reflect the potential impact of liquidating a position in an
orderly manner over a reasonable period of time under present market
conditions.
Changes in the market value of the Company's trading contracts, resulting
primarily from the impact of commodity price and interest rate movements, are
recognized in operating income in the period of change. Unrealized gains and
losses of these trading contracts are recorded as assets and liabilities,
respectively, from price risk management.
In addition to the trading activities discussed above, the Company engages
in non-trading activities using futures, forward contracts, options, and swaps
to hedge the impact of market fluctuations on energy commodity prices, interest
rates, and foreign currencies when there is a high degree of correlation
between price movements in the derivative and the item designated as being
hedged. Before the implementation date of Statement of Financial Accounting
Standards ("SFAS") No. 133, as described below, the Company accounted for
hedging activities under the deferral method, whereby the Company deferred
unrealized gains and losses on hedging transactions. When the underlying item
settled, the Company recognized the gain or loss from the hedge instrument in
operating income. In instances where the anticipated correlation of price
movements did not occur, hedge accounting was terminated and future changes in
the value of the derivative were recognized as gains or losses. If the hedged
item was sold, the value of the associated derivative was recognized in income.
In 1998, the Emerging Issues Task Force ("EITF") of the Financial Accounting
Standards Board ("FASB") reached a consensus on Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities ("EITF 98-
10"). EITF 98-10 was implemented by the Company on January 1, 1999 and required
energy trading contracts to be recorded at fair value on the balance sheet,
with the changes in fair value included in income. Prior to the implementation
of EITF 98-10, Energy Trading recorded its trading activities at fair value;
therefore, the adoption of EITF 98-10 did not have any impact on the Company's
consolidated financial position or results of operations as of and for the year
ended December 31, 1999.
The Company adopted SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, as amended by SFAS Nos. 137 and 138 (collectively, the
"Statement"), on January 1, 2001. The Statement requires the Company to
recognize all derivatives, as defined in the Statement, on the balance sheet at
fair value. Effective January 1, 2001, derivatives are classified as price risk
management assets and liabilities. Derivatives, or any portion thereof, that
are not effective hedges must be adjusted to fair value through income. If
derivatives are effective hedges, depending on the nature of the hedges,
changes in the fair value of derivatives either will offset the change in fair
value of the hedged assets, liabilities, or firm commitments through earnings,
or will be recognized in other comprehensive income until the hedged items are
recognized in earnings. The Company has several types of derivatives designated
as cash flow hedges, including interest rate swaps used to hedge interest
payments on variable-rate debt and forwards, futures and swaps used to hedge
energy commodity price risk. The Company also uses foreign currency swaps as
hedges of exchange rate risk. The Company also has certain derivative commodity
contracts for the physical delivery of purchase and sale quantities transacted
in the normal course of business. These derivatives are exempt from the
requirements of
F-13
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
SFAS No. 133 under the normal purchases and sales exception, and thus are not
reflected on the balance sheet at fair value. In June 2001, the FASB approved
an interpretation issued by the Derivatives Implementation Group ("DIG") that
changes the definition of normal purchases and sales for certain power
contracts; the Company must implement this interpretation on July 1, 2001. The
FASB is currently considering another DIG interpretation that would change the
definition of normal purchases and sales for certain other commodity contracts.
Certain of the Company's derivative commodity contracts may no longer be exempt
from the requirements of the Statement. The Company is evaluating the impact of
this implementation guidance on its financial statements, and will implement
this guidance, as applicable, on a prospective basis.
The Company's transition adjustment to implement this new standard was an
immaterial adjustment to net income and a negative adjustment of $333 million
(after-tax) to other comprehensive income, a component of stockholder's equity.
This transition adjustment, which relates to hedges of interest rate, foreign
currency and commodity price risk exposure, was recognized as of January 1,
2001, as a cumulative effect of a change in accounting principle.
Hedge effectiveness is measured at least quarterly. Any ineffectiveness is
recognized in the income statement in the period that the ineffectiveness
occurs. If a derivative instrument that has qualified for hedge accounting is
liquidated or sold prior to maturity, the gain or loss at the time of
termination remains in other comprehensive income (loss) until the hedged item
impacts earnings. For derivative instruments not designated as hedges, the gain
or loss is immediately recognized in earnings in the period of its change in
value. Derivative gains and losses deferred in other comprehensive income
(loss) are reclassified into earnings when the related hedged item affects
earnings.
Net gains and losses on derivative instruments recognized in earnings for
the six months ended June 30, 2001 were classified in various captions,
including operating revenues, cost of commodity sales and fuel and interest
expense.
As of June 30, 2001, the maximum length of time over which the Company has
hedged exposure to the variability of future cash flows associated with
commodity price risk is through December 2005 and exposure to interest rate
risk is through March 2014.
Regulation--GTN's rates and charges for its natural gas transportation
business are regulated by the Federal Energy Regulatory Commission ("FERC").
The consolidated financial statements reflect the ratemaking policies of the
FERC in conformity with SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation. This standard allows GTN to record certain regulatory
assets and liabilities that will be included in future rates and would not be
recorded under generally accepted accounting principles for nonregulated
entities in the United States.
F-14
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's regulatory assets and liabilities consist of the following (in
millions):
December 31,
-------------
1999 2000
------ ------
Regulatory assets:
Income tax related........................................... $25 $25
Deferred charge on reacquired debt........................... 11 10
Pension costs................................................ 3 1
Postretirement benefit costs other than pensions............. 2 2
Fuel tracker................................................. 4 3
--- ---
Total regulatory assets.................................... $45 $41
=== ===
Regulatory liabilities:
Postretirement benefit costs other than pensions............. $ 4 $ 6
--- ---
Total regulatory liabilities............................... $ 4 $ 6
=== ===
Regulatory assets and liabilities represent future probable increases or
decreases, respectively, in revenue to be recorded by GTN associated with
certain costs to be collected from or refunded to customers as a result of the
ratemaking process. GTN's regulatory assets are provided for in rates charged
to customers and are being amortized over future periods in conjunction with
the regulatory recovery period. Regulatory assets are included in other
noncurrent assets on the consolidated balance sheets. GTN does not earn a
return on regulatory assets on which it does not incur a carrying cost. GTN
does not earn a return nor does it incur a carrying cost on regulatory assets
related to income taxes, pension costs, postretirement benefit costs, or fuel
tracker. Regulatory liabilities are included in other noncurrent liabilities on
the consolidated balance sheets.
Cash and Cash Equivalents--Cash and cash equivalents consist of highly
liquid investments with original maturities of 90 days or less.
Restricted Cash--Restricted cash includes cash and cash equivalent amounts,
as defined above, which are restricted under the terms of certain agreements
for payment to third parties, primarily for debt service.
Inventory--Inventory consists principally of materials and supplies, coal,
natural gas, natural gas liquids, and fuel oil. Inventory is valued at the
lower of average cost or market, except for the gas storage inventory of ET,
which is recorded at fair value.
Property, Plant, and Equipment--Property, plant, and equipment is recorded
at cost, which includes costs of purchased equipment, related labor and
materials, and interest during construction. Property, plant, and equipment
purchased as part of an acquisition is reflected at fair value on the
acquisition date. These capitalized costs are depreciated on a straight-line
basis over estimated useful lives, less any residual or salvage value. Routine
maintenance and repairs are charged to expense as incurred.
Interest is capitalized as a component of projects under construction and is
amortized over the projects' estimated useful lives. During 1998, 1999, and
2000, the Company capitalized interest of approximately $1 million, $8 million,
and $22 million, respectively.
GTN utility plant also includes an allowance for funds used during
construction ("AFUDC"). AFUDC is the estimated cost of debt and equity funds
used to finance regulated plant additions. AFUDC rates, calculated in
accordance with FERC authorizations, are based upon the last approved return on
equity and an embedded rate for borrowed funds. The equity component of AFUDC
is included in other income and the borrowed funds
F-15
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
component is recorded as a reduction of interest expense. The costs of utility
plant additions for GTN, including replacements of plant retired, are
capitalized. The original cost of plant retired plus removal costs, less
salvage, is charged to accumulated depreciation upon retirement of plant in
service. No gain or loss is recognized upon normal retirement of utility plant.
Property, plant, and equipment consists of the following (in millions):
December 31,
Estimated -------------- June 30,
Lives 1999 2000 2001
-------------- ------ ------ -----------
(unaudited)
Electric generating facilities..... 20 to 50 years $1,789 $1,955 $2,527
Gas transmission................... 15 to 40 years 2,383 1,477 1,481
Other.............................. 2 to 20 years 298 190 197
Land............................... 137 125 130
------ ------ ------
4,607 3,747 4,335
Less: Accumulated depreciation..... (770) (757) (821)
------ ------ ------
Property, plant, and equipment--
net............................... 3,837 2,990 3,514
Construction in progress........... 217 650 350
------ ------ ------
$4,054 $3,640 $3,864
====== ====== ======
Included in property, plant, and equipment are assets held for sale relating
to GTT at December 31, 1999, of $1,032 million less accumulated depreciation of
$122 million. Also included in property, plant, and equipment is a GTN capital
lease for an office building of approximately $18 million as of December 31,
1999 and 2000.
Effective April 1, 1999, the estimated useful lives of gas-fired electric
and hydro-generating plants were changed from 35 years to 45 and 50 years,
respectively. The change resulted in an increase in net income of approximately
$4 million during 1999.
Depreciation expense, including amortization expense under capital leases,
was $134 million, $180 million, and $123 million for the years ended December
31, 1998, 1999, and 2000, respectively.
Project Development Costs--Project development costs represent amounts
incurred for professional services, direct salaries, permits, options and other
direct incremental costs related to the development of new property, plant and
equipment, principally electric generating facilities and gas transmission
pipelines. These costs are expensed as incurred until development reaches a
stage when it is probable that the project will be completed. A project is
considered probable of completion upon meeting one or more milestones which may
include a power sales contract, gas transmission contract, obtaining a viable
project site, securing project construction or operating permits, among others.
Project development costs that are incurred after a project is considered
probable of completion but prior to starting physical construction are
capitalized. Project development costs are included in construction in progress
when physical construction begins. The Company periodically assesses project
development costs for impairment. Project development costs are included in
other noncurrent assets in the consolidated balance sheets.
Prepaid Expenses and Deposits--Prepaid expenses and deposits consist
principally of margin cash for commodities futures and over-the-counter
financial instruments, cash on deposit with counterparties and option premiums
paid at the inception of a contract. Option premiums are recorded as expense
upon exercise or expiration of the option. Deposits will be refunded to the
Company at the time at which all obligations have been fulfilled.
F-16
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Goodwill and Other Intangible Assets--The Company amortizes the excess of
purchase price over fair value of net assets of businesses acquired (goodwill)
using the straight-line method over periods ranging from 3 to 35 years. The
Company periodically assesses goodwill for impairment.
Intangible assets include the value assigned, based on the expected benefits
to be received, to acquired management service agreements, operations and
maintenance agreements (collectively, the "Service Agreements"), and power
sales agreements ("PSA"). These intangible assets are being amortized on a
straight-line basis over their estimated useful lives, ranging from 3 to 35
years. Intangible assets are included in other noncurrent assets in the
accompanying consolidated balance sheets.
Amortization expense related to goodwill and other intangible assets was $24
million, $26 million, and $13 million for the years ended December 31, 1998,
1999, and 2000, respectively.
Out-of-Market Contractual Obligations--Commitments contained in the
underlying Power Purchase Agreements ("PPAs"), gas commodity and transportation
agreements (collectively, the "Gas Agreements"), and Standard Offer Agreements,
acquired in September 1998 (see Note 4), were recorded at fair value, based on
management's estimate of either or both the gas commodity and gas
transportation markets and electric markets over the life of the underlying
contracts, discounted at a rate commensurate with the risks associated with
such contracts. Standard Offer Agreements reflect a commitment to supply
electric capacity and energy necessary for certain New England Electric System
("NEES") affiliates to meet their obligations to supply fixed-rate service.
PPAs and Gas Agreements are amortized on a straight-line basis over their
specific lives. The Standard Offer Agreements are amortized using an
accelerated method since the decline in value is greater in earlier years due
to increasing contract pricing terms reducing the obligation to supply service
over time. The carrying value of the out-of-market obligations is as follows
(in millions):
December 31, June 30,
-------------------------
Amortization Period 1999 2000 2001
------------------- ------- -----------------
(unaudited)
PPAs............................. 1-20 years $ 660 $ 599 $570
Gas Agreements................... 8-13 years 205 188 180
Standard Offer Agreements........ 6-7 years 239 154 118
------- ----- ----
1,104 941 868
Less: Current portion............ 163 141 129
------- ----- ----
Long-term portion................ $ 941 $ 800 $739
======= ===== ====
Other Liabilities--Other current liabilities consist primarily of cash
received by the Company at the time option contracts are sold and cash on
deposit from counterparties. Option premiums are recorded as income upon
exercise or expiration of the option. Deposits will be returned by the Company
at the time in which all obligations under the forward contracts have been
fulfilled.
Asset Impairment--The Company periodically evaluates long-lived assets,
including property, plant, and equipment, goodwill, and specifically
identifiable intangibles, when events or changes in circumstances indicate that
the carrying value of these assets may not be recoverable. The determination of
whether an impairment has occurred is based on an estimate of undiscounted cash
flows attributable to the assets, as compared to the carrying value of the
assets. Asset impairment is then measured using a fair market value or
discounted cash flows method.
Revenue Recognition--Revenues derived from power generation are recognized
upon output, product delivery, or satisfaction of specific targets, all as
specified by contractual terms. Regulated gas transmission
F-17
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
revenues, including the reservation and the volumetric charge components, are
recorded as services are provided, based on rate schedules approved by the
FERC. The reservation charge component is recorded in the month in which it
applies. The volumetric charge component is recorded when volumes are
delivered.
Staff Accounting Bulletin No. 101, Revenue Recognition ("SAB No. 101") was
issued by the SEC on December 3, 1999. SAB No. 101, as amended, summarizes
certain of the SEC staff's views in applying generally accepted accounting
principles to revenue recognition in financial statements. The adoption of
SAB No. 101 did not have a material impact on the consolidated financial
statements.
Income Taxes--The Company accounts for income taxes under the liability
method. Deferred tax assets and liabilities are determined based on the
difference between financial statement carrying amounts and tax basis of assets
and liabilities, using currently enacted tax rates.
The Company and its subsidiaries are included in the federal consolidated
tax return of the Parent. The Company and its subsidiaries have a tax-sharing
arrangement with the Parent that provides for the allocation of federal and
certain state income taxes. In consideration of the Company's participation in
such consolidated return and the tax-sharing arrangement, the Company
recognizes its pro rata share of consolidated income tax expenses and benefits.
The Company is allowed to use the tax benefits generated as long as these
benefits could be used on a consolidated basis. Certain states require that
each entity doing business in that state file a separate tax return (the
"Separate State Taxes"). Canadian subsidiaries are subject to Canadian federal
and provincial income taxes based on net income (the "Canadian Taxes"). Tax
consequences of the Separate State Taxes and the Canadian Taxes are excluded
from the tax-sharing arrangement and thus are separately accounted for by the
Company. Beginning with the 2001 calendar year, the Company expects to pay to
the Parent the amount of income taxes that the Company would be liable for if
the Company filed its own consolidated combined or unitary return separate from
the Parent, subject to certain consolidated adjustments.
Comprehensive Income--The Company's comprehensive income consists of net
income and other items recorded directly to the equity accounts. The objective
is to report a measure of all changes in equity of an enterprise that result
from transactions and other economic events of the period other than
transactions with owners. The Company's other comprehensive income consists
principally of foreign currency translation adjustments and, subsequent to
December 31, 2000, deferred gains and losses on derivative instruments
accounted for as cash flow hedges in accordance with SFAS No. 133.
Foreign Currency Translation--The asset and liability accounts of the
Company's foreign subsidiaries are translated at year-end exchange rates and
revenue and expenses are translated at average exchange rates prevailing during
the period. The resulting translation adjustments are included in other
comprehensive income. Currency transaction gains and losses are recorded in
income.
Stock-Based Compensation--The Company accounts for stock-based employee
compensation arrangements in Parent stock using the intrinsic value method in
accordance with provisions of Accounting Principles Board ("APB") Opinion No.
25, Accounting for Stock Issued to Employees, and complies with the disclosure
provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Under APB
Opinion No. 25, compensation cost is generally recognized based on the
difference, if any, on the date of grant between the fair value of the
Company's stock and the amount an employee must pay to acquire the stock.
Cumulative Effect of Change in Accounting Method--The Company currently
recognizes the cost of repairs and maintenance as incurred. The Company adopted
this method for its power generation assets on January 1, 1999. Previously, the
Company recognized the estimated cost of major overhauls for these assets
ratably over the scheduled overhaul cycle of the related equipment. The
cumulative effect of this change in accounting principle increased 1999
earnings by $12 million, net of taxes of $8 million. In addition, the
F-18
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company reduced property, plant, and equipment by approximately $17 million for
amounts previously accrued in a purchase price allocation. If the cumulative
effect had been recorded in 1998, then the pro forma effect (unaudited) for
1998 would have increased earnings by $4.5 million.
New Accounting Pronouncements--In June 2001, the FASB issued SFAS No. 141,
Business Combinations. This standard prohibits the use of pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001
and applies to all business combinations accounted for under the purchase
method that are completed after June 30, 2001. The Company does not expect that
implementation of this standard will have a significant impact on its financial
statements.
Also in June 2001, the FASB issued SFAS No. 142, Goodwill and Other
Intangible Assets. This standard eliminates the amortization of goodwill, and
requires goodwill to be reviewed periodically for impairment. This standard
also requires the useful lives of previously recognized intangible assets to be
reassessed and the remaining amortization periods to be adjusted accordingly.
This standard is effective for fiscal years beginning after December 15, 2001,
for all goodwill and other intangible assets recognized on the Company's
statement of financial position at that date, regardless of when the assets
were initially recognized. The Company has not yet determined the effects of
this standard on its financial statements.
In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This standard is effective for fiscal years beginning after June
15, 2002, and provides accounting requirements for asset retirement obligations
associated with tangible long-lived assets. The Company has not yet determined
the effects of this standard on its financial statements.
4. ACQUISITIONS AND SALES
In July 1998, the Company, through the Parent, sold its Australian energy
holdings for $126 million. The Company recognized a loss of approximately $23
million related to the sale, which is included in other income (expense) on the
consolidated statements of operations.
In September 1998, Gen, through its indirect subsidiary USGen New England,
Inc. ("USGenNE"), acquired a portfolio of electric generating assets and power
supply agreements, including inventories and certain other assets, from a
wholly owned subsidiary of NEES. The purchase price was approximately
$1.8 billion, funded through $1.3 billion of debt and a $425 million equity
contribution from the Parent. The net purchase price was allocated as follows:
electric generating assets of $2.3 billion classified as property, plant, and
equipment; long-term receivables of $0.8 billion; and out-of-market contractual
obligations of $1.3 billion. The purchase price of the acquisition was
allocated to the acquired assets and identifiable intangible assets and the
liabilities assumed based upon an assessment of fair value at the date of
acquisition. The assets acquired included hydroelectric, coal, oil, and natural
gas generation facilities with a combined generating capacity of 4,000 MW. In
addition, USGenNE assumed 23 multi-year power purchase agreements representing
an additional 800 MW of production capacity. USGenNE entered into agreements as
part of the acquisition which (1) provided that a wholly owned subsidiary of
NEES would make payments through January 2008 for the power purchase
agreements, and (2) required that USGenNE provide electricity to certain NEES
affiliates under contracts that expire at various times through 2008.
In December 1999, Parent's Board of Directors approved a plan to dispose of
ES, its wholly owned subsidiary, through a sale. The disposal has been
accounted for as a discontinued operation and the Company's investment in ES
was written down to its estimated net realizable value. In addition, the
Company provided a reserve for anticipated losses through the date of sale. The
total provision for discontinued operations was $58 million, net of income
taxes of $36 million at December 31, 1999. Of this amount, $33 million (net of
taxes) was allocated toward operating losses for the period leading up to the
intended disposal date. In 2000,
F-19
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
$31 million (net of taxes) of actual operating losses was charged against this
reserve. During the second quarter of 2000, the Company finalized the
transactions related to the disposal of the energy commodity portion of ES for
$20 million, plus net working capital of approximately $65 million, for a total
of $85 million. In addition, a portion of the ES business and assets was sold
on July 21, 2000, for a total consideration of $18 million. For the year ended
December 31, 2000, an additional loss of $40 million, net of income tax of $36
million, was recorded as actual losses in connection with the disposal, which
exceeded the original 1999 estimate. The principal reason for the additional
loss was due to the mix of assets, and the structure and timing of the actual
sales agreements, as opposed to the one reflected in the initial provision
established in 1999. In addition, the worsening energy situation in California
contributed to the actual loss incurred.
On January 27, 2000, the Company signed a definitive agreement with El Paso
Field Services Company ("El Paso") providing for the sale to El Paso, a
subsidiary of El Paso Energy Corporation, of the stock of GTT. Given the terms
of the sales agreement, in 1999 the Company recognized a charge against pre-tax
earnings of $1,275 million, to reflect GTT's assets at their fair value. The
composition of the pre-tax charge is as follows: (1) an $819 million write-down
of net property, plant, and equipment, (2) the elimination of the unamortized
portion of goodwill in the amount of $446 million, and (3) an accrual of $10
million representing selling costs.
On December 22, 2000, after receipt of governmental approvals, the Company
completed the stock sale. The total consideration received was $456 million,
less $150 million used to retire the GTT short-term debt, and the assumption by
El Paso of GTT long-term debt having a book value of $564 million. The final
sales price, which is subject to a working capital true-up adjustment, is
expected to be finalized in the third quarter of 2001. GTT's total assets and
liabilities, including the charge noted above, included in the Company's
Consolidated Balance Sheets at December 31, 1999, are as follows (in millions):
As of
December 31,
1999
------------
Assets:
Current assets................................................ $ 229
Noncurrent assets............................................. 988
------
Total assets................................................ 1,217
------
Liabilities:
Current liabilities........................................... 448
Noncurrent liabilities........................................ 624
------
Total liabilities........................................... 1,072
------
Net assets.................................................. $ 145
======
The following table reflects GTT's results of operations included in the
Company's consolidated statements of operations for the years ended December
31, 1998, 1999, and 2000 (in millions):
Year Ended December
31,
-----------------------
1998 1999 2000
------ ------- ------
Revenue............................................. $2,064 $ 1,753 $1,912
Operating expenses.................................. 2,114 3,058 1,831
------ ------- ------
Operating (loss) income............................. (50) (1,305) 81
Interest expense and other--net..................... (51) 7 (52)
------ ------- ------
(Loss) income before income taxes................... (101) (1,298) 29
Income tax benefit.................................. (31) (390) (4)
------ ------- ------
Net (loss) income................................. $ (70) $ (908) $ 33
====== ======= ======
F-20
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On September 28, 2000, the Company, through its indirect subsidiary APC,
purchased for $311 million the Attala Generating Company, LLC, which owned a
gas-fired power plant then under construction. Under the purchase agreement,
the Company prepaid the estimated remaining construction costs, which are being
managed by the seller. The project, which was approximately 75% complete as of
December 31, 2000, began commercial service in June 2001. In connection with
the acquisition, the Company also assumed industrial revenue bonds in the
amount of $159 million. The seller has agreed to pay off the bonds prior to
December 15, 2001; accordingly, the Company has recorded a receivable equal to
the amount of the outstanding bonds and accrued interest at December 31, 2000.
Subsequent Events (unaudited)--On June 29, 2001, the Company contracted to
supply the full service power requirements of the city of Denton, Texas, for a
period of five years beginning July 1, 2001. The city of Denton's peak load
forecast is 280 megawatts in 2001, increasing to 314 megawatts over the contact
term. The Company's supply obligation to the city is net of approximately 97
megawatts of generation entitlements retained by the city, plus 40 megawatts of
purchased power that the city has assigned to the Company for summer 2001. In
connection with the power supply agreement, the Company acquired a 178-megawatt
generating station and has agreed to acquire two small hydroelectric facilities
from the city. Total consideration of approximately $12 million was allocated
between the fair value of the power supply contract, recorded as an intangible
asset, and property, plant and equipment.
On December 6, 2000, the Company agreed to sell one of its development
projects. The sale closed on July 10, 2001, and the Company recorded an after-
tax gain of approximately $14 million. Also on December 6, 2000, the Company
entered into a tolling agreement that will entitle the Company to receive up to
250 MW of the project's production for a ten-year period commencing at
commercial operation. As part of this tolling arrangement, the Company agreed
to provide guarantees of up to $40 million, which are included in the total
guarantees as of December 31, 2000.
F-21
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
5. PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading and Nontrading Activities--The following tables summarize the
contract or notional amounts and maturities of the Company's commodity
derivatives used for trading and nontrading activities related to commodity
price risk management as of December 31, 1999 and 2000.
Natural Gas, Electricity, and Natural Gas Liquids Contracts
(billions of MMBTU (a) equivalents)
Derivative Purchase Sale Max Term
Trading Activities Type (Long) (Short) (Years)
- ------------------ ---------- -------- ------ --------
December 31, 1999.......................... Swaps 2.38 2.33 7
Options 0.94 0.86 8
Futures 0.19 0.18 2
Forwards 1.49 1.36 12
December 31, 2000.......................... Swaps 2.04 1.95 6
Options 0.46 0.37 8
Futures 0.14 0.15 3
Forwards 1.42 1.38 16
Nontrading Activities
- ---------------------
December 31, 1999.......................... Swaps -- -- --
Options -- -- --
Futures -- -- --
Forwards 0.02 0.01 3
December 31, 2000.......................... Swaps -- -- --
Options -- -- --
Futures -- -- --
Forwards 1.70 0.74 22
- --------
(a) Million British Thermal Units. Electric power contracts, measured in
megawatts, were converted to MMBtu equivalents using a conversion factor
of 10 MMBtu to one megawatt-hour.
The notional amounts and maturities of nontrading commodity derivatives
provided above are representative of the extent of the Company's activity in
this area. Because the changes in market value of these derivatives used as
hedges are generally offset by changes in the value of the underlying physical
transactions, the amounts at risk are significantly lower than these notional
amounts might suggest.
The Company's net gains (losses) on trading contracts held during the years
ended December 31, 1998, 1999 and 2000 are as follows (in millions):
Year Ended December 31,
-----------------------
Derivative Type 1998 1999 2000
- --------------- ------- ------- --------
Swaps............................................... $ 69 $ 15 $ 173
Options............................................. (49) (41) 66
Futures............................................. (63) (36) (106)
Forwards............................................ 101 96 72
------- ------- --------
Total............................................... $ 58 $ 34 $ 205
======= ======= ========
The Company's net gains on trading contracts for the six months ended June
30, 2001 were $121 million.
F-22
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table discloses the estimated average fair value and ending
fair value of trading price risk management assets and liabilities as of
December 31, 1999 and 2000 (in millions).
Average Fair
Values Ending Fair Values
------------------ ------------------
Fair Values Assets Liabilities Assets Liabilities
- ----------- ------ ----------- ------ -----------
Values as of December 31, 1999
Swaps..................................... $ 218 $ 197 $ 50 $ 33
Options................................... 75 87 56 41
Futures................................... 89 119 35 58
Forwards.................................. 475 356 567 398
------ ------ ------ ------
Total..................................... $ 857 $ 759 $ 708 $ 530
====== ====== ====== ======
Noncurrent portion........................ $ 319 $ 207
Current portion........................... $ 389 $ 323
Values as of December 31, 2000
Swaps..................................... $ 163 $ 75 $ 286 $ 121
Options................................... 153 106 250 171
Futures................................... 34 78 33 98
Forwards.................................. 2,053 1,921 3,496 3,476
------ ------ ------ ------
Total..................................... $2,403 $2,180 $4,065 $3,866
====== ====== ====== ======
Noncurrent portion........................ $2,026 $1,867
Current portion........................... $2,039 $1,999
In valuing its electric power, natural gas, and natural gas liquids
portfolios, the Company considers a number of market risks and estimated costs
and continuously monitors the valuation of identified risks and adjusts them
based on present market conditions. Considerable judgment is required to
develop the estimates of fair value; thus, the estimates provided herein are
not necessarily indicative of the amounts that the Company could realize in the
current market.
Generally, exchange-traded futures contracts require deposit of margin cash,
the amount of which is subject to change based on market movement and in
accordance with exchange rules. Margin cash requirements for over-the-counter
financial instruments are specified by the particular instrument and are
settled monthly. Both exchange-traded and over-the-counter options contracts
require payment or receipt of an option premium at the inception of the
contract.
Interest Rate Swaps--At December 31, 1999 and 2000, the Company had entered
into interest rate swap agreements with aggregate notional amounts of $666
million and $1.7 billion, respectively, to manage interest rate exposure on
construction and term loan debt. These agreements expire between 2001 and 2012.
With respect to certain interest rate swap agreements entered into by the
Company on behalf of the lessor of certain projects, the terms of reimbursement
agreements permit the Company to pass swap payments and receipts through to the
lessor during the construction phase of the projects. Through these pass-
through provisions, the Company effectively retains no risk or reward related
to these interest rate swap agreements.
Revenue Hedging Activities--The Company entered into hedge transactions with
the intention to preserve a portion of certain revenue streams over the term of
its contracts. The costs associated with the hedging instruments are recognized
in income over the same period that the revenue stream is recognized.
F-23
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Quantitative Information About Cash Flow Hedges (unaudited)--As described in
Note 3, the Company adopted SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, on January 1, 2001. The Company's cash flow hedges,
recorded in accordance with SFAS No. 133, include hedges of commodity price
risk, interest rate risk and foreign currency exchange rate risk. The Company's
ineffective portion of changes in fair values of cash flow hedges is immaterial
for the six-month period ended June 30, 2001. The Company expects that net
derivative losses of $35 million (before taxes) included in other comprehensive
income as of June 30, 2001 will be reclassified into earnings within the next
twelve months.
The table below summarizes the effect of derivative activities on
accumulated other comprehensive income (loss) for the six months ended June 30,
2001 (in millions, unaudited).
Beginning accumulated derivative net loss at January 1, 2001............ $(333)
Net gain from current period hedging transactions....................... 156
Net reclassification to earnings........................................ 112
-----
Ending accumulated derivative net loss at June 30, 2001................. (65)
Foreign currency translation adjustment................................. (2)
-----
Ending accumulated other comprehensive loss at June 30, 2001............ $ (67)
=====
Credit Risk--The use of financial instruments to manage the risks associated
with changes in energy commodity prices creates exposure resulting from the
possibility of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The counterparties in the Company's portfolio consist
primarily of investor-owned and municipal utilities, energy trading companies,
financial institutions, and oil and gas production companies. The Company
minimizes credit risk by dealing primarily with creditworthy counterparties in
accordance with established credit approval practices and limits. The Company
assesses the financial strength of its counterparties at least quarterly and
requires that counterparties post security in forms of cash, letters of credit,
corporate guarantees of acceptable credit quality, or eligible securities if
current net receivables and replacement cost exposure exceeds contractually
specified limits. The Company has experienced no material losses due to the
nonperformance of counterparties through December 31, 2000. At December 31,
2000, the Company had outstanding an aggregate gross credit exposure to the top
five counterparties of $372 million.
Financial Instruments--The Company's financial instruments consist of cash
and cash equivalents, restricted cash, accounts receivable, accounts payable
and certain accrued liabilities, long-term receivables, notes payable,
commercial paper, capital leases, long-term debt, interest rate swap
agreements, and financial hedges.
The fair value of these financial instruments, with the exception of fixed
rate debt, long-term receivables, interest rate swaps, and financial hedges
approximates their carrying value as of December 31, 1999 and 2000, due to
their short-term nature or due to the fact that the interest rate paid on the
instrument is variable.
The fair value of long-term debt was estimated using discounted cash flows
analysis, based on the Company's current incremental borrowing rate and the
approximate carrying value based on currently quoted market prices for similar
types of borrowing arrangements. Similarly, the fair values of long-term
receivables were calculated using a discounted cash flows analysis.
F-24
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The fair value of interest rate swap agreements, which are not carried on
the consolidated balance sheets, is estimated by calculating the present value
of the difference between the total estimated payments to be made and received
under the interest rate swap agreements (using contract terms) and the total
payments recalculated using appropriate current market rates. The carrying
amount and fair value of long-term receivables, long-term debt and interest
rate swaps as of December 31, 1999 and 2000 is summarized as follows (in
millions):
1999 2000
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------- -------- -------
Long-term receivables....................... $ 680 $ 680 $ 611 $ 526
Financial hedges............................ $ -- $ -- $ -- $ (199)
Long-term debt.............................. $(1,898) $(1,920) $(1,407) $(1,461)
Interest rate swaps......................... $ -- $ (11) $ -- $ (74)
6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
The Company has investments in various power generation and other energy
projects. The equity method of accounting is applied to such investments in
affiliated entities, which include corporations, joint ventures and
partnerships, due to the ownership structure preventing the Company from
exercising control over operating and financial policies. Under this method,
the Company's share of equity income or losses of these entities is reflected
as equity in earnings of affiliates.
Operating entities which the Company does not control are as follows (in
millions):
NEG's Share
of Entity
as of NEG's
December 31, Investment
--------------- --------------
Project 1999 2000 1999 2000
- ------- ------ ------ ----- -----
Carney's Point............................. 50% 50% $ 49 $ 50
Cedar Bay.................................. 64% 64% 69 63
Colstrip................................... 64% 17% 17 6(a)
Indiantown................................. 35% 35% 33 32
Logan...................................... 50% 50% 42 52
MASSPOWER.................................. 13% 13% 20(b) 22
Northampton................................ 50% 50% 22 24
Panther Creek.............................. 55% 55% 59 57
Scrubgrass................................. 50% 50% 38 39
Selkirk.................................... 42% 42% 109 58
Iroquois Gas Transmission.................. 4% 4% 11 9
Mid Texas Pipeline......................... 50% 0% 31 --(c)
San Jacinto Pipeline....................... 50% 0% 30 --(c)
True Quote................................. 0% 46% -- 4
Other investments.......................... -- -- -- 1
----- -----
Total.................................... $ 530 $ 417
===== =====
- --------
(a) In January 2000, NEG sold a 47% interest in Colstrip to third parties.
(b) In September 1999, NEG sold a 31% interest in MASSPOWER to third parties.
(c) The NEG's interests in the Mid Texas Pipeline and the San Jacinto Pipeline
were sold as part of the GTT disposition.
F-25
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Net gains from the sale of interests in unconsolidated affiliates were $19
million and $21 million for 1999 and 2000, respectively, excluding the
Company's pipeline interests that were sold as part of the GTT disposition.
Amounts are included in other operating expenses.
The following table sets forth summarized financial information of the
Company's investments in affiliates accounted for under the equity method for
the years ended December 31, 1998, 1999, and 2000 (in millions):
Year Ended December
31
--------------------
Statement of Operations Data 1998 1999 2000
---------------------------- ------ ------ ------
Revenues............................................... $1,074 $1,067 $1,252
Income from operations................................. 526 524 491
Earnings before taxes.................................. 139 149 197
As of
December 31
-----------
Balance Sheet Data 1999 2000
------------------ ------ ------
Current assets................................................ $ 317 $ 272
Noncurrent assets............................................. 3,992 3,617
------ ------
Total assets................................................ $4,309 $3,889
====== ======
Current liabilities........................................... $ 301 $ 233
Noncurrent liabilities........................................ 3,355 3,112
Equity........................................................ 653 544
------ ------
Total liabilities and equity................................ $4,309 $3,889
====== ======
The reconciliation of the Company's share of equity to investment balance is
as follows (in millions):
1999 2000
---- ----
The Company's share of equity.................................. $237 $122
Purchase premium over book value............................... 145 136
Lease receivables and other investments........................ 148 159
---- ----
Investments in unconsolidated affiliates....................... $530 $417
==== ====
The purchase premium over book value is being amortized over periods ranging
from 16 to 35 years and is recorded through amortization expense. The purchase
premium amortization expenses were $9 million, $8 million, and $7 million for
the years ended December 31, 1998, 1999, and 2000, respectively.
F-26
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
7. LONG-TERM RECEIVABLES
The Company receives payments from a wholly owned subsidiary of NEES,
related to the assumption of power supply agreements, that are payable monthly
through January 2008. As of December 31, 2000, future cash receipts under this
arrangement are as follows (in millions):
2001................................................................ $119
2002................................................................ 120
2003................................................................ 112
2004................................................................ 107
2005................................................................ 107
Thereafter.......................................................... 225
----
790
Discounted portion.................................................. (179)
----
Net amount receivable............................................... 611
Less: Current portion............................................... 75
----
Long-term receivable................................................ $536
====
The long-term receivables are valued at the present value of the scheduled
payments using a discount rate that reflects NEES' credit rating on the date of
acquisition. The current portion is included in prepaid expenses, deposits, and
other in the consolidated balance sheets.
8. SHORT-TERM BORROWINGS AND CREDIT FACILITIES
The Company maintains $1,350 million in five revolving credit facilities
which support commercial paper and Eurodollar borrowing arrangements. At
December 31, 1999 and 2000, the Company had total outstanding balances related
to such borrowings of $1,173 million and $1,181 million, respectively. In
addition, certain letters of credit held by the Company reduce the available
outstanding facility commitments. At December 31, 2000, approximately $37
million letters of credit were outstanding under these facility arrangements.
Since the Company has the ability and intent to refinance certain borrowings,
$649 million and $662 million of such borrowings are classified as long-term
debt as of December 31, 1999 and 2000, respectively (see Note 9). The remaining
outstanding balances are classified as short-term borrowings in the
consolidated balance sheets. As of December 31, 1999 and 2000, the weighted
average interest rate on borrowings outstanding related to the credit
facilities was 5.58% and 7.09%, respectively.
Certain credit agreements contain, among other restrictions, customary
affirmative covenants, representations and warranties and are cross-defaulted
to the Company's other obligations. The credit agreements also contain certain
negative covenants including restrictions on the following: consolidations,
mergers, sales of assets and investments; certain liens on the Company's
property or assets; incurrence of indebtedness; entering into agreements
limiting the right of any subsidiary of the Company to make payments to its
shareholders; and certain transactions with affiliates. Certain credit
agreements also require that the company maintain a minimum ratio of cash flow
available for fixed charges to fixed charges and a maximum ratio of funded
indebtedness to total capitalization.
A wholly owned subsidiary of the Company has a demand note payable to the
Parent of $309 million for the purchase of Attala Generating Company. Interest
on this note is based on one of several market-based indices, including prime
and commercial paper rates, and is payable quarterly in arrears.
F-27
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Subsequent Events (unaudited)--On June 15, 2001, the Company entered into a
$550 million revolving credit facility to support energy trading operations and
other working capital requirements. This facility, which has an initial term of
364 days, provides for bank borrowings and letters of credit. Borrowings under
the facility bear interest based on LIBOR plus a credit spread. On June 18,
2001, the Company reduced one of its existing revolving credit facilities by
$50 million to meet the requirements of the new $550 million facility.
Also, on May 29, 2001, a subsidiary of the Company entered into a revolving
credit facility of up to $280 million. Borrowings under this facility were used
to purchase all turbines from the two master turbine trusts (see Note 13) and
will be used to fund future turbine payments and equipment purchases associated
with the development of generating facilities. This facility, which expires on
December 31, 2003, provides for bank borrowings. Borrowings under the facility
bear interest based on LIBOR plus a credit spread.
If the Company's credit ratings were downgraded below investment grade, the
Company would be required to provide alternative credit enhancement, such as
guarantees of the Company's investment grade subsidiaries, letters of credit or
cash collateral. If the Company were unable to provided such enhancements
within 30 days, the guaranteed loans would be due and payable within five days.
9. LONG-TERM DEBT
Long-term debt consists of the following (in millions):
Description Maturity Interest Rate 1999 2000
----------- -------- ------------- ---- ----
GTT First Mortgage Notes.......................... 2000-2009 10.02% to 11.50% $ 333 $ --
Senior Notes.................................. 1999 10.58% -- --
Medium Term Notes............................. 2001-2009 7.35% to 9.25% 229 --
Stock Margin Loan............................. 2003 LIBOR + 0.40% 8 --
Premium on long-term debt..................... 2000-2009 N/A 63 --
GTN Senior Notes (unsecured)...................... 2005 7.10% 250 250
Senior Debentures (unsecured)................. 2025 7.80% 150 150
Medium Term Notes (non-recourse).............. 2000-2003 6.61% to 6.96% 70 39
Outstanding Credit Facilities (Note 8)........ 2002 Various 99 87
Capital lease obligations..................... 2015 8.80% 16 15
Discounts..................................... (3) (3)
Gen Bonds payable (non-recourse).................. 2010 10% -- 159
Term Loans (non-recourse)..................... 2009-2011 Various 116 107
Outstanding Credit Facilities (Note 8)........ 2003 Various 550 575
30-day commercial
Mortgage loan payable......................... 2010 paper rate plus 6.07% 9 8
Other......................................... 8 20
------ ------
1,898 1,407
Less: Current Portion......................... 93 17
------ ------
Total long-term debt, net of current portion.. $1,805 $1,390
====== ======
The GTT first mortgage notes were comprised of three series due annually
through 2009, and were secured by mortgages and security interests in the
natural gas transmission and natural gas processing facilities and other real
and personal property of GTT. The mortgage indenture required semi-annual
payments with one-half of each interest payment and one-fourth of each annual
principal payment escrowed quarterly in advance. The mortgage indenture also
contained covenants that restricted the ability of GTT to incur additional
indebtedness and precluded cash distributions if certain cash flow coverages
were not met. In January 2000,
F-28
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
GTT obtained an amendment that provided GTT the ability to redeem in whole or
in part, its Mortgage Notes, including the premium set forth in the Mortgage
Note Indenture, anytime after January 1, 2000. These notes were assumed by the
buyer of GTT as of December 22, 2000 (see Note 4).
APC, a wholly owned indirect subsidiary of the Company, assumed the
Industrial Development Revenue Bonds (Series 2000) issued by the Mississippi
Business Finance Corporation (bonds payable) through the acquisition of the
Attala Generating Company, LLC. The Industrial Development Revenue Bonds mature
on January 2010, bear a fixed interest of 10 percent and are redeemable at the
option of the Company prior to maturity. In accordance with the purchase
agreement, after completion of construction, but not later than December 2001,
the seller has agreed to pay off the outstanding bonds. Accordingly, the
Company has recorded a receivable equal to the outstanding balance of the bonds
and accrued interest at December 31, 2000.
Other long-term debt consists of non-recourse project financing associated
with unregulated generating facilities, premiums, and other loans.
At December 31, 2000, annual scheduled maturities of long-term debt during
the next five years were as follows (in millions):
2001................................................................ $ 17
2002................................................................ 128
2003................................................................ 591
2004................................................................ 10
2005................................................................ 260
Thereafter.......................................................... 401
------
Total............................................................. $1,407
======
Interest expense, net of capitalized interest, for the years ended December
31, 1998, 1999, and 2000, was $156 million, $162 million, and $155 million,
respectively.
Subsequent Event (unaudited)--On May 22, 2001, the Company issued senior
notes in an aggregate principal amount of $1 billion. These notes, which mature
on May 16, 2011, bear interest at 10.375% and require semiannual interest
payments on May 15 and November 15. The Company has the option to redeem any or
all of the notes before maturity at the greater of the outstanding principal
balance or an amount equal to the present value of remaining principal and
interest due on the notes, discounted using the rate on a United States
Treasury Security of comparable maturity plus 50 basis points, in either case
plus accrued interest. The notes, which are senior obligations of PG&E National
Energy Group, Inc. and rank pari passu with borrowings under the Company's new
$550 million revolving credit facility, are subordinated to indebtedness of the
Company's subsidiaries. The notes received investment grade credit ratings from
Standard & Poor's and Moody's. The indenture for the senior notes contains
cross-default provisions that provide that an event of default under any
instrument that secures or evidences indebtedness of the Company in excess of
$50 million, which event of default results in the acceleration of such
indebtedness, constitutes an event of default under the senior notes. Under the
Company's new $550 million revolving credit facility, a failure of the Company
to maintain its investment grade status is an event of default that entitles
the lender to accelerate the debt, which would trigger a cross default under
the senior notes.
The Company intends to use the proceeds from the senior notes issuance, net
of $26 million of debt discount and note issuance costs, to fund investments in
generating facilities and pipeline assets, working
F-29
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
capital requirements and other general corporate requirements. The Company has
filed a registration statement with the U.S. Securities and Exchange Commission
to commence an exchange offer to allow the senior note holders to exchange
their senior notes for exchange notes with substantially similar terms as the
senior notes.
10. PREFERRED STOCK OF SUBSIDIARY
Preferred stock consists of $57 million of preferred stock issued by a
subsidiary of the Company that owns an interest in the Cedar Bay Project. The
preferred stock, with $100 par value, has a stated non-cumulative dividend of
$3.35 per share, per quarter, and is redeemable when there is an excess of
available cash. There were 549,594 shares outstanding at December 31, 1999 and
2000.
11. EMPLOYEE BENEFIT PLANS
Certain subsidiaries of the Company provide separate noncontributory defined
benefit pension plans, and "Other Retirement Benefits" including contributory
defined benefit medical plans, and noncontributory benefit life insurance plans
for employees and retirees as set forth in the plan agreements.
The following table reconciles the plans' funded status (the difference
between fair value of plan assets and the related benefit obligation) to the
accrued liability recorded on the consolidated balance sheet as of and for the
years ended December 31, 1999 and 2000 (in millions):
Other
Pension Retirement
Benefits Benefits
---------- ------------
1999 2000 1999 2000
---- ---- ----- -----
Change in Plan Assets:
Benefit obligation at January 1..................... $ 43 $ 43 $ 35 $ 32
Service cost........................................ 2 1 2 --
Interest cost....................................... 3 3 2 1
Divestiture......................................... -- (7) -- (17)
Actuarial loss/gain................................. (3) (2) (6) (1)
Benefits paid....................................... (2) (2) (1) --
---- ---- ----- -----
Benefit Obligation, December 31....................... $ 43 $ 36 $ 32 $ 15
==== ==== ===== =====
Change in Plan Assets:
Fair value of plan assets at January 1.............. $ 43 $ 51 $ 10 $ 13
Actual return on plan assets........................ 9 (1) 2 --
Divestiture......................................... -- (1) -- --
Employer contributions.............................. 2 -- 2 2
Benefits paid....................................... (3) (2) (1) --
---- ---- ----- -----
Fair Value of Plan Assets, December 31................ $ 51 $ 47 $ 13 $ 15
==== ==== ===== =====
Plan assets in excess of benefit obligation......... $ 8 $ 11 $ (19) $ --
Unrecognized actuarial gain......................... (19) (15) (7) (5)
Unrecognized net transition obligation.............. -- -- 5 5
---- ---- ----- -----
Accrued liability................................... $(11) $ (4) $ (21) $ --
==== ==== ===== =====
As of December 31, 1999 and 2000, the defined benefit pension plan for the
employees of GTN had plan assets in excess of benefit obligations of $13
million and $11 million, respectively. The defined benefit pension
F-30
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
plan for employees of GTT had benefit obligations in excess of plan assets of
$5 million as of December 31, 1999 and was transferred to the purchaser of GTT
upon its divestiture in 2000 (see Note 4).
The unrecognized net actuarial gains are amortized on a straight-line basis
over the average remaining service period of active participants. The
unrecognized net transition obligation for pension benefits and other benefits
are being amortized over 20 years.
Net periodic benefit cost (income) was as follows (in millions):
Pension Benefits Other Benefits
--------------------- ----------------
1998 1999 2000 1998 1999 2000
----- ------ ----- ---- ---- ----
Components of net periodic benefit
cost:
Service cost...................... $ 1 $ 2 $ 1 $ 1 $ 1 $ --
Interest cost..................... 3 3 2 2 2 1
Expected return on plan assets.... (4) (4) (4) (1) (1) (1)
Actuarial gain recognized......... (1) (1) (1) -- -- --
Settlement gain................... -- -- (6) -- -- (18)
Transition amount amortization.... -- -- -- 1 1 --
----- ------ ----- --- --- ----
Net periodic benefit cost
(income)....................... $ (1) $ -- $ (8) $ 3 $ 3 $(18)
===== ====== ===== === === ====
The following actuarial assumptions were used in determining the plans'
funded status and net periodic benefit cost (income). For Other Retirement
Benefits, the expected return on plan assets and rate of future compensation is
for the plan held by GTN only, as the other plans are not funded. Year-end
assumptions are used to compute funded status, while prior year-end assumptions
are used to compute net benefit cost (income).
Pension Benefits Other Benefits
--------------------- ----------------
1998 1999 2000 1998 1999 2000
----- ----- ----- ---- ---- ----
Assumptions as of December 31:
Discount rate............................ 7.0% 7.5% 7.5% 7.0% 7.5% 7.5%
Expected return on plan assets........... 9.0% 8.5% 8.5% 8.0% 8.0% 8.5%
Rate of future compensation increase..... 5.0% 5.0% 5.0% 2.9% 2.9% 2.9%
The assumed health care cost trend rate for 2001 is approximately 8.5%,
grading down to an ultimate rate in 2005 of approximately 6.0%. The assumed
health care cost trend rate can have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following effects (in millions):
1-Percentage 1-Percentage
Point Point
Increase Decrease
------------ ------------
Effect on total of service and interest cost
components..................................... $0.2 $(0.1)
Effect on postretirement benefit obligation..... $1.7 $(1.4)
Defined Contribution Plans--Employees of the Company are eligible to
participate in several different defined contribution plans, as set forth by
the specific subsidiary for which they work. In 1999, the assets of several of
these plans were transferred to a defined contribution plan maintained by
Parent. The contribution percentages and employer contribution options are set
forth in each specific plan. Employer contributions totaled approximately $13
million, $15 million, and $14 million for 1998, 1999 and 2000, respectively.
F-31
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Regulatory Matters--In conformity with SFAS No. 71, regulatory adjustments
for GTN have been recorded for the difference between pension cost determined
for accounting purposes and that for ratemaking, which is based on a funding
approach. The FERC's ratemaking policy with regard to Other Retirement Benefits
provides for the recognition, as a component of cost-based rates, of allowances
for prudently incurred costs of such benefits when determined on an accrual
basis that is consistent with the accounting principles set forth in SFAS No.
106, Employers' Accounting for Post-retirement Benefits Other Than Pensions,
subject to certain funding conditions.
As required by the FERC's policy, GTN established irrevocable trusts to fund
all benefit payments based upon a prescribed annual test period allowance of $2
million. To the extent actual SFAS No. 106 accruals differ from the annual
funded amount, a regulatory asset or liability is established to defer the
difference pending treatment in the next general rate case filing. Based upon
this treatment, GTN had over collected $4 million at December 31, 1999 and $6
million at December 31, 2000. Plan assets consist primarily of common stock,
fixed-income securities, and cash equivalents.
Long-term Incentive Program--Employees of the Company participate in the
Parent's Long-term Incentive Program ("Program") that provides for grants of
stock options to eligible participants with or without associated stock
appreciation rights and dividend equivalents. The following disclosures relate
to the Company employees' share of benefits under the program. Options granted
in 1998, 1999, and 2000, of 1,757,700, 2,378,341, and 3,712,218, respectively,
had weighted average fair value at date of grant of approximately $3.81, $4.19,
and $3.26, respectively, using the Black-Scholes valuation method. In addition,
the Parent granted 10,741 shares to the Company employees on January 2, 2001,
at an option price of $19.56, and 2,199,400 shares on January 5, 2001 at an
option price of $12.63, the then-current market price. Significant assumptions
used in the Black-Scholes valuation method for shares granted in 1998, 1999,
and 2000 were: expected stock price volatility of 17.60%, 16.79%, and 20.19%,
respectively; expected dividend yield of 4.47%, 3.77%, and 5.18%, respectively;
risk-free interest rate of 6.03%, 4.69%, and 6.10%, respectively; and an
expected 10-year life for all periods.
Outstanding stock options become exercisable on a cumulative basis at one-
third each year commencing two years from the date of grant and expire ten
years and one day after the date of grant. Shares outstanding at December 31,
2000, had option prices ranging from $19.81 to $33.50 and a weighted-average
remaining contractual life of 9.2 years. As permitted under SFAS No. 123,
Accounting for Stock-Based Compensation, the Parent applies APB Opinion No. 25
in accounting for the program. As the exercise price of all stock options are
equal to their fair market value at the time the options are granted, the
Company did not recognize any compensation expense related to the program using
the intrinsic value based method. Had compensation expense been recognized
using the fair value based method under SFAS No. 123, the Company's
consolidated earnings would have decreased by $0.5 million, $2.0 million, and
$3.6 million in 1998, 1999, and 2000, respectively.
In addition, certain employees of the Company participate in the Parent's
Performance Unit Plan that provides incentive compensation to participants
based upon the year-end stock price of the Parent and a predetermined
compensation group. For the years ended December 31, 1998, 1999, and 2000, the
compensation expense under this program for Company employees was $1.1 million,
$0.8 million, and $0.3 million, respectively.
F-32
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
12. INCOME TAXES
The significant components of income tax expense (benefit) from continuing
operations were as follows (in millions):
1998 1999 2000
----- ----- ----
Current--Federal........................................ $(104) $ (68) $(26)
Current--State.......................................... (5) (9) (8)
----- ----- ----
Total current......................................... (109) (77) (34)
----- ----- ----
Deferred--Federal....................................... 127 (288) 149
Deferred--State......................................... 23 14 15
----- ----- ----
Total deferred........................................ 150 (274) 164
----- ----- ----
Total income tax expense (benefit).................... $ 41 $(351) $130
===== ===== ====
Foreign taxes included above............................ $ 5 $ (5) $ 4
===== ===== ====
The differences between reported income taxes and tax amounts determined by
applying the federal statutory rate of 35 percent to income before income tax
expense were as follows (in millions):
1998 1999 2000
---- ------- ----
Income (loss) from continuing operations before income
taxes................................................... $44 $(1,141) $322
Federal statutory rate................................... 35% 35% 35%
--- ------- ----
Income tax expense (benefit) at statutory rate........... 15 (399) 113
Increase (decrease) in income tax expense resulting from:
State income tax (net of federal benefit).............. 6 7 5
Effect of foreign earnings............................. 10 (5) 6
Amortization of goodwill............................... 4 7 1
Stock sale valuation allowance......................... -- 79 --
Stock sale differences................................. -- (17) (10)
Receivable differences................................. -- -- 12
Unitary tax true-up.................................... -- (20) --
Other--net............................................. 6 (3) 3
--- ------- ----
Effective tax............................................ $41 $ (351) $130
=== ======= ====
F-33
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The significant components of net deferred income tax liabilities were as
follows (in millions):
1999 2000
---- ----
Deferred Income Tax Assets:
Standard offer agreements........................................ $ 98 $ 63
Gas purchase agreements.......................................... 84 77
Net operating loss carryovers.................................... 32 52
Capital loss carryovers.......................................... 131 42
Deferred income.................................................. 8 7
Accrued liabilities.............................................. -- 10
Other............................................................ 17 28
---- ----
Total deferred income tax assets............................... 370 279
Less: Valuation allowance........................................ (97) (69)
---- ----
Total deferred income tax assets--net.......................... 273 210
---- ----
Deferred Income Tax Liabilities:
Accelerated depreciation......................................... 405 467
Partnership earnings............................................. 233 204
Purchase premium over book value................................. 75 83
Power purchase agreements........................................ 8 5
Price risk management activities................................. 81 122
Leveraged lease.................................................. 44 47
Other............................................................ 22 38
---- ----
Total deferred income tax liabilities.......................... 868 966
---- ----
Total Net Deferred Income Taxes.................................... $595 $756
==== ====
Classification of Net Deferred Income Taxes:
Included in current assets....................................... $(55) $(36)
Included in deferred income taxes--Noncurrent liability.......... 650 792
---- ----
Total Net Deferred Income Taxes.................................... $595 $756
==== ====
The Company has $75 million of permanently invested funds that relate to
foreign undistributed earnings.
13. COMMITMENTS AND CONTINGENCIES
Letters of Credit--The Company has entered into various letter of credit
facilities to provide the issuance of letters of credit necessary during the
ordinary course of business. The letter of credit facilities expire between
November 2001 and December 2004 and total $220 million. As of December 31,
2000, the Company had issued approximately $116 million of letters of credit.
Gas Supply, Firm Transportation, and Power Purchase Agreements--The
Company, through its subsidiaries Gen and ET, has entered into various gas
supply and firm transportation agreements with various pipelines and
transporters. Under these agreements, the Company must make specified minimum
payments each month.
Furthermore, through its indirect subsidiary USGenNE, Gen assumed rights
and duties under several power purchase contracts with third party independent
power producers as part of the acquisition of the NEES assets. As of December
31, 2000, these agreements provided for an aggregate of 800 MW of capacity.
Under the transfer agreement, the Company is required to pay to NEES amounts
due to third-party producers under the power purchase contracts.
F-34
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The approximate dollar obligations to pay under power purchase agreements,
gas supply agreements and firm transportation agreements are as follows (in
millions):
Gas Supply and
Power Purchase Transportation
Agreements Agreements
-------------- --------------
2001........................................... $ 228 $ 87
2002........................................... 215 87
2003........................................... 217 87
2004........................................... 220 85
2005........................................... 220 85
Thereafter..................................... 1,585 708
------ ------
$2,685 $1,139
====== ======
Standard Offer Agreements--USGenNE entered into three Standard Offer
Agreements with NEES' retail subsidiaries under which USGenNE will provide
"standard offer" service to such subsidiaries. The Standard Offer Agreements
initially covered all of the retail customers served by NEES' distribution
subsidiaries in Rhode Island, New Hampshire, and Massachusetts, at the date of
acquisition. The Standard Offer Agreements continue through December 31, 2004,
in Massachusetts, and December 31, 2009, in Rhode Island. The pricing per
megawatt-hour is standard for all contracts and was below market prices at the
date of the Agreement. On January 7, 2000, USGenNE paid $15 million by entering
into an agreement with a third party, which assumed the obligation to deliver
power to NEES to serve 10% of the Massachusetts customers and 40% of the Rhode
Island customers under the terms of the Standard Offer Agreements. The payment
was recorded as a deferred standard offer fee and is amortized over the
remaining life of the standard offer agreements.
Operating Leases--The Company and its subsidiaries have entered into several
operating lease agreements for generating facilities and office space. Lease
terms vary between 3 and 48 years. In November 1998, a subsidiary of the
Company entered into a $479 million sale-leaseback transaction whereby the
subsidiary sold and leased back a pumped storage station under an operating
lease.
During 1999 and 2000, two indirect wholly owned subsidiaries of the Company
entered into two operating lease commitments relating to projects that are
under construction, for which they act as the construction agent for the
lessors. Upon completion of the construction projects, expected to be in 2002,
the lease terms of 2 years and 3 years, respectively, will commence. At the
conclusion of each of the operating lease terms, the Company has the option to
extend the leases at fair market value, purchase the projects or act as
remarketing agent for the lessors for sales to third parties. If the Company
elects to remarket the projects, then the Company would be obligated to the
lessors for up to 85% of the project costs, if the proceeds are deficient to
pay the lessor's investors. The Parent has committed to fund up to $604 million
in the aggregate of equity to support the company's obligation to the lessors
during the construction and post-construction periods.
Subsequent Event (unaudited)--As of June 30, 2001, the Company had replaced
the Parent equity support commitments with its own guarantees. If the Company's
credit ratings are downgraded below investment grade, it would be required to
provide alternate credit enhancements. Failure to provide alternate credit
enhancements would lead to payment acceleration and ultimate foreclosure on
project assets and calls on the guarantees. If the Company was unable to
perform under the guarantees, the Company may be in default under senior
obligations, including the senior notes.
F-35
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The approximate lease obligations, including those based on estimated total
cost of projects under construction as of December 31, 2000, are as follows (in
millions):
2001.................................................................. $ 97
2002.................................................................. 159
2003.................................................................. 166
2004.................................................................. 162
2005.................................................................. 88
Thereafter............................................................ 965
------
$1,637
======
Operating lease expense amounted to $39 million, $70 million, and $70
million in 1998, 1999 and 2000, respectively.
In addition to those obligations described above, the Company entered into
operative agreements with a special purpose entity that will own and finance
construction of a facility totaling $775 million. The Parent has committed to
fund up to $122 million of equity support commitments to meet the obligations
to the entity. The Company is in the process of negotiating a post-construction
operating lease arrangement. As discussed in Note 2, in 2001, the Company
replaced the Parent equity support commitments with substitute commitments of
NEG.
Turbine and Construction Commitments--On September 8, 2000, the Company,
through one of its subsidiaries, entered into operative documents with a
special purpose entity (the "Lessor") in order to facilitate the development,
construction, financing, and leasing of several power generation projects. The
Lessor has an aggregate financing commitment from debt and equity participants
(the "Investors") of $7.8 billion. The Company, in its role as construction
agent for the Lessor, is responsible for completing construction by the sixth
anniversary of the closing date, but has limited its risk related to
construction completion to less than 90% of project costs incurred to date.
Upon completion of an individual project, the Company is required to make lease
payments to the Lessor in an amount sufficient to provide a return to the
Investors. At the end of an individual project's operating lease term (three
years from construction completion), the Company has the option to extend the
lease at fair value, purchase the project at a fixed amount (equal to the
original construction cost), or act as remarketing agent for the Lessor and
sell the project to an independent third party. If the Company elects the
remarketing option, the Company may be required to make a payment to the
Lessors, up to 85% of the project cost, if the proceeds from remarketing are
deficient to repay the Investors. The Parent has committed to fund up to $314
million of equity to support the Company's obligations to the Lessor during the
construction and post-construction periods.
Subsequent Event (unaudited)--On May 31, 2001, the Company terminated the
agreements covered by the operative documents executed with the Lessor related
to these power generation projects. Using borrowings from the newly-arranged
$280 million revolving credit facility (see Note 8), the Company purchased all
turbines previously owned by the Lessor in two master turbine trusts. The
purchased equipment totaled $216 million and was recorded as a long-term
prepaid asset included in other noncurrent assets as of May 31, 2001.
Tolling Agreements--In 1999 and 2000, the Company, through ET, has entered
into tolling agreements with several counterparties allowing the Company the
right to sell electricity generated by facilities owned and operated by other
parties which are under construction until June 2003. Under the tolling
agreements, the Company, at its discretion, supplies the fuel to the power
plants, then sells the plant's output in the competitive market. Committed
payments are reduced if the plant facilities do not achieve agreed-upon levels
of
F-36
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
performance criteria. At December 31, 2000, the annual estimated committed
payments under such contracts range from approximately $21 million to $304
million, resulting in total committed payments over the next 28 years of
approximately $6.2 billion, commencing at the completion of construction.
Estimated amounts payable in future years are as follows (in millions):
2001.................................................................. $ 21
2002.................................................................. 98
2003.................................................................. 220
2004.................................................................. 280
2005.................................................................. 285
Thereafter............................................................ 5,300
------
$6,204
======
During 2000, the Company paid total committed payments of approximately $12
million under tolling arrangements.
Subsequent Event (unaudited)--In May 2001, the Company extended a contingent
financing commitment to the owner of a project for which the Company has
executed a tolling agreement. The Company committed to provide a subordinated
loan of up to $75 million to the project owner at the time of completion of the
project, if at that time the Company does not meet certain credit rating
criteria as agreed upon with the counterparty to the tolling contract.
Payments in Lieu of Property Taxes--The Company has entered into certain
agreements with local governments that provide for payments in lieu of property
taxes. Future payments for agreements in place as of December 31, 2000 are as
follows (in millions):
2001.................................................................... $ 17
2002.................................................................... 16
2003.................................................................... 13
2004.................................................................... 7
2005.................................................................... 7
Thereafter.............................................................. 65
----
$125
====
Construction Project--An indirect wholly owned subsidiary of Gen contracted
with Siemens Westinghouse Power ("SWP") in 2000 to provide the combustion
turbine generator, steam turbine generator and heat recovery steam generator
for its 1,080 MW natural gas-fired combined cycle power plant under development
in Green County, New York. The total contract value is approximately $223
million. At December 31, 2000, approximately $69 million has been paid under
the contract. Construction commenced before June 30, 2001.
Guarantees--The Company and its subsidiaries have made guarantees to third
parties to support the Company's development and construction activities. As of
December 31, 2000, the total amount of the guarantees was $57.4 million. As of
June 30, 2001, the Company's guarantees included a guarantee of $87 million of
the purchase price of a pending acquisition, $27 million related to the
contractors and power purchasers of another development project and $47 million
in connection with a pipeline development project.
F-37
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Labor Subject to Collective Bargaining Agreements--Approximately 30% of
NEG's employees are subject to one of five collective bargaining agreements.
Such agreements are ongoing in nature. One of the agreements is a 34-month
agreement expiring December 31, 2001. The remaining agreements are 30-month
agreements all expiring November 11, 2001.
Legal Matters--The Company is involved in various litigation matters in the
ordinary course of its business.
Litigation Involving Generating Projects--In December, 1997, Cedar Bay
Generating Company, LP, ("Cedar Bay") an unconsolidated affiliate of the
Company, filed a breach of contract action relating to a long-term power
purchase agreement against a third party. On August 12, 1999, a jury returned a
verdict in Cedar Bay's favor for $18 million. The case was appealed by the
third party, and on October 30, 2000, the District Court of Appeal affirmed the
judgment. The third party had asked for a rehearing, but on January 2, 2001,
the District Court of Appeals declined a rehearing. The Company's affiliate has
collected $15 million from the settlement and has recognized revenue in January
2001.
Logan Generating Company, LP ("Logan"), an unconsolidated affiliate of the
Company, initiated an arbitration proceeding against a third party, seeking a
declaration that a PPA allow it to establish certain procedures for determining
Logan's heat rate upon which energy payments to Logan are based, and that the
procedure which Logan has established for this purpose is therefore proper
under the PPA. In addition, Logan claims the costs of the arbitration. The
third party counterclaimed, contending that Logan's heat rate testing procedure
is a breach of the PPA, and seeks (1) an order declaring that Logan's heat rate
testing procedure must conform to that used by the plant's construction
contractor in final acceptance testing, (2) damages and other relief based in
part on recalculation of past energy payments using heat rates lower than those
reported by Logan in prior invoices in the amount of approximately $7 million,
plus interest, and (3) an order declaring that the third party is allowed to
terminate the PPA because of Logan's heat rate testing procedure. Hearings are
under way and it is too early to predict if the claim will lead to an
unfavorable outcome or reasonably estimate the amount of a potential loss.
Except as described in the paragraph above, the Company is not currently
involved in any litigation that is expected, either individually or in the
aggregate, to have a material adverse effect on the Company's financial
condition or results of operations.
Energy Trading Litigation--A third-party power marketer filed suit in
October 1998 against ET. The Plaintiff claims, in sum and substance, that ET
breached various alleged agreements between the parties that the plaintiff
asserts were created at the time certain sales of electricity by plaintiff, ET,
and others were scheduled for delivery. The Plaintiff further claims that: (1)
ET tortuously interfered with power sales agreements plaintiff had executed
with certain third parties and (2) ET made certain misrepresentations that were
fraudulent or negligent. In addition, plaintiff alleges that ET was unjustly
enriched as a result of the foregoing. This power marketer seeks to recover
damages of approximately $6 million, an unspecified amount of punitive damages,
costs and other relief, including monies allegedly received by ET as a result
of its purported unjust enrichment. In 1999, the court granted plaintiff's
motion to join two other power marketers in the lawsuit. These other power
marketers seek recovery from ET of approximately $0.7 million. At this time,
management does not believe that the outcome of this litigation will have a
material adverse effect on the Company's financial condition or results of
operations.
A creditor's involuntary bankruptcy petition was filed in August 1998
against a power marketing entity. ET is an unsecured creditor of this entity.
As part of the bankruptcy, the bankruptcy court created a liquidating trust
(the "Trust") and appointed a trustee to act on behalf of the Trust. The
trustee has alleged, among other
F-38
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
things, that ET improperly terminated transactions with the bankrupt power
marketer. In December 1999, ET filed an action in federal court in Texas
("Texas Action") seeking a declaration from the court that termination of the
transactions with the bankrupt power marketer was not a breach of the
agreements. Subsequently, the trustee filed suit in the bankruptcy court
("Bankruptcy Action") alleging, among other things, breach of contract, various
torts, unjust enrichment, improvement in position, and preference. The lawsuit
seeks approximately $32 million in actual damages, plus punitive damages in an
unspecified amount. The parties have agreed to dismiss the Texas Action and the
Bankruptcy Action without prejudice. They have also agreed that the case, if
not settled, would be heard in federal court in Connecticut. The parties are
now participating in various mediation proceedings underway in connection with
the Bankruptcy Action and discovery is continuing. At this time, management
does not believe that the outcome of this litigation will have a material
adverse effect on the Company's financial condition or results of operations.
On May 14, 2001, NSTAR Electric & Gas Corporation, or NSTAR, the Boston-area
retail electric distribution utility holding company, filed a complaint at FERC
contesting the market-based rate authority of ET-Power and affiliates of Sithe
Energies, Inc., or Sithe. In support of its complaint, NSTAR argues that the
Northeastern Massachusetts Area, or NEMA, at times suffers transmission
constraints which limit the delivery of power into NEMA and that ET-Power and
Sithe possess market power based on their share of generation within NEMA.
NSTAR requests remedies including revocation of the suppliers' market-based
pricing authority during periods of transmission congestion into NEMA,
divestiture of generation resources in NEMA, imposition of a rate cap on the
suppliers' generation resources during transmission constraints based on the
marginal cost of production of those resources, and more effective and open
exercise of market monitoring and mitigation by ISO-New England, the
independent system operator for the New England control area, or NEPOOL.
Under the NEPOOL market rules and procedures, ISO-New England is empowered
to monitor and mitigate bids during periods of transmission congestion. The
Company believes that ISO-New England has actively mitigated bids and has used
its authority to minimize the impact of transmission constraints on costs
within NEMA and that ET-Power has operated its resources in compliance with
NEPOOL market rules and procedures and applicable law. In addition, ET-Power
and its affiliate, USGen New England, the entity which owns the generating
assets located in NEPOOL, have had their market-based rate authority confirmed
by FERC on two prior occasions. The Company believes that these complaints are
without merit and intend to present a vigorous defense. At this time,
management does not believe that the outcome of this litigation will have a
material adverse effect on the Company's financial condition or result of
operations.
Other Litigation--The Company and/or its subsidiaries are parties to
additional claims and legal proceedings arising in the ordinary course of
business. The Company believes it is unlikely that the final outcome of these
other claims would have a material adverse effect on the Company's financial
statements.
In accordance with SFAS No. 5, Accounting for Contingencies, the Company
makes a provision for a liability when both it is probable that a liability has
been incurred and the amount of the loss can be reasonably estimated. In 1999,
the Company reduced the amount of the recorded liability for legal matters
related to pending litigation at GTT, by approximately $55 million. The
remaining liability is assumed by the buyer of GTT. This adjustment is
reflected in Other income (expenses)--net in the Company's consolidated
statements of operations.
Environmental Matters--In May 2000, the Company received an Information
Request from the U.S. Environmental Protection Agency ("EPA"), pursuant to
Section 114 of the Federal Clean Air Act ("CAA"). The Information Request asked
the Company to provide certain information, relative to the compliance of the
Company's Brayton Point and Salem Harbor Generating Stations with the CAA. No
enforcement action has been brought by the EPA to date. The Company has had
very preliminary discussions with the EPA to explore
F-39
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
a potential settlement of this matter. As a result of this and related
regulatory initiatives by the Commonwealth of Massachusetts, the Company is
exploring initiatives that would assist the Company to achieve significant
reductions of sulfur dioxide and nitrogen oxide emissions by as early as 2006
to 2010. Management believes that the Company would meet these requirements
through installation of controls at the Brayton Point and Salem Harbor plants.
As of June 30, 2001, management estimates that capital expenditures on these
environmental projects will be approximately $265 million through 2006.
Management believes that it is not possible to predict at this point whether
any such settlement will occur or in the absence of a settlement the likelihood
of whether the EPA will bring an enforcement action.
Gen's existing power plants, including USGen New England, Inc. ("USGenNE")
facilities, are subject to federal and state water quality standards with
respect to discharge constituents and thermal effluents. Three of the fossil-
fueled plants owned and operated by USGenNE are operating pursuant to NPDES
permits that have expired. For the facilities whose NPDES permits have expired,
permit renewal applications are pending, and its is anticipated that all three
facilities will be able to continue to operate under existing terms and
conditions until new permits are issued. As of June 30, 2001, it is estimated
that USGenNE's cost to comply with the new permit conditions could be as much
as $60 million through 2005. It is possible that the new permits may contain
more stringent limitations than prior permits.
In September 2000, the Company settled a legal claim through certain
agreements that require the Company to alter its existing wastewater treatment
facilities at its Brayton Point and Salem Harbor generating facilities. The
Company began the activities during 2000 and is expected to complete them in
2001. In addition to costs incurred in 2000, at December 31, 2000, the Company
recorded a reserve in the amount $3.2 million relating to its estimate of the
remaining environmental expenses to fulfill its obligations under the
agreement. In addition, the Company expects to incur approximately $4 million
in capital expenditures during 2001 to complete the project.
14. RELATED-PARTY TRANSACTIONS
In addition to the intercompany balances due to and from the Parent
discussed in Note 2, the Company generates amounts receivable from and payable
to the Parent and the Utility through the normal course of operations.
The Parent--The Company and its affiliates are charged for administrative
and general costs from the Parent. These charges are based upon direct
assignment of costs and allocations of costs using allocation methods that the
Company and the Parent believe are reasonable reflections of the utilization of
services provided to or for the benefits received by the Company. For the years
ended December 31, 1998, 1999, and 2000, allocated costs totaled $17 million,
$31 million, and $43 million, respectively. The total amount due its Parent at
December 31, 1999 and 2000, was $6 million and $21 million, respectively. In
addition, the Company bills Parent for certain shared costs. For the years
ended December 31, 1998, 1999 and 2000, the total charges billed to the Parent
were $-0- million, $0.3 million, and $0.8 million, respectively. The amounts
receivable from the Parent at December 31, 1999 and 2000, were $0.3 million,
and $1.3 million, respectively.
During the periods covered by these financial statements, the Company
invested its available cash balances with, or borrowed from, the Parent on an
interim basis pursuant to a pooled cash management arrangement. The balance
advanced to the Parent under this cash management program was $2.0 million at
an interest rate of 5.4% as of December 31, 1999. The interest rate on these
cash investments or borrowings averaged 5.0% in 1999 and 6.2% in 2000. The
related interest income was $0.1 million in 1999 and $0.3 million in 2000. As
described in Note 2, the Company terminated its intercompany borrowing and cash
management programs with the Parent in 2000.
F-40
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On October 26, 2000, the Company loaned $75 million to Parent pursuant to a
promissory note. The principal amount of this investment is payable upon demand
and is reflected as note receivable from Parent on the consolidated balance
sheets. The balance at December 31, 2000, is $75 million at an interest rate of
6.9%. The interest rate on this cash investment averaged 6.8% in 2000.
ET enters into transactions with related parties, including financing
activities and purchases and sales of energy commodities. As of December 31,
1999, ET had $136 million in short-term demand borrowings due to the Parent.
This loan was a variable rate loan that accrued interest at the London
Interbank Offering Rate ("LIBOR"), which was approximately 5.8% at December 31,
1999. At December 31, 1999, the Company also had a $48 million fixed-rate
demand note receivable from the Parent. This note accrued interest at an annual
rate of 8.0%. Due to the floating rate and short-term nature of the two notes,
respectively, the fair value of these financial instruments approximated their
carrying values at December 31, 1999. Additionally, ET had a long-term fixed
rate note payable to the Parent of $58 million as of December 31, 1999. As of
December 31, 1999, ET had accrued approximately $11 million, net, in interest
expense related to these borrowings. As described in Note 2, the Company
terminated its intercompany borrowing program with the Parent in 2000.
Also, through the periods covered by these financial statements, the Parent
issued guarantees, surety bonds, and letters of credit on behalf of the Company
to support its energy trading activities and structured tolling activities. As
of December 31, 1999 and 2000, the Parent had issued $793 million and $2.4
billion in these types of instruments. As described in Note 2, the Company
replaced these Parent-backed security mechanisms with other means of credit
support (including guarantees provided by the Company and its subsidiaries and
credit facilities negotiated with third parties) during 2001.
Pacific Gas and Electric Company--The Company incurs and bills direct
charges from and to the Utility for shared services. For the years ended
December 31, 1998, 1999, and 2000, the total charges were $1.3 million, $5.5
million, and $0.9 million, respectively. At December 31, 1999 and 2000, the
total amounts payable to the Utility were $1.9 million and $1.9 million,
respectively. In addition, the amounts receivable from the Utility related to
shared services at December 31, 1999 and 2000, were $-0- million and $1
million, respectively.
ET enters into transactions with related parties, including the Utility. The
nature of these transactions is the purchasing and selling of energy
commodities and general corporate business items. For the years ended December
31, 1998, 1999, and 2000, ET had energy commodity sales of approximately $0.8
million, $30 million, and $136 million to the Utility and energy commodity
purchases of $0.7 million, $7 million, and $12 million, respectively. As of
December 31, 1999 and 2000, ET had trade receivables relating to energy
commodity transactions from the Utility of $-0- million and $1.2 million,
respectively, and trade payables relating to energy commodity transactions to
the Utility of $-0- million and $1.2 million, respectively.
In 1998, 1999 and 2000, the Utility and its affiliates accounted for
approximately $49 million, $47 million and $46 million, respectively, of GTN's
transportation revenues. In accordance with GTN's FERC tariff provisions, the
Utility has provided assurances either in the form of cash, or an investment
grade guarantee, letter of credit, or surety bond to support its position as a
shipper on the GTN pipeline. In the event that the Utility is unable to
continue to provide such assurances, then GTN can mitigate its risks by open
market capacity sales. Because of the tariff structure, coupled with the strong
demand for natural gas, GTN expects that it could sell the capacity at a price
at least equal to what the Utility is currently paying. As a result of the
Utility's April 6, 2001 filing with the U.S. Bankruptcy Court, all amounts owed
to GTN by the Utility for transportation services on that date were suspended
pending the decision of the bankruptcy court. As of April 6, 2001, the Utility
owed GTN $2.9 million. The Utility is current on all subsequent obligations
incurred for the transportation services provided by GTN and has indicated its
intention to remain current.
F-41
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
15. SEGMENT INFORMATION
The Company is currently managed under two reportable operating segments,
which were determined based on similarities in economic characteristics,
products and services, types of customers, methods of distribution and
regulatory environment, and how information is reported to key decision makers.
The first business segment is composed of Integrated Energy and Marketing
Activities, principally the generation and energy trading operations which are
managed and operated in a highly integrated manner. The second business segment
is Interstate Pipeline Operations. See Note 4 for more discussion of the sale
of GTT from the Interstate Pipeline Operations. Segment information for the
years 1998, 1999 and 2000 and for the six months ended June 30, 2000 and 2001
was as follows (in millions):
Integrated
Energy and Interstate Other and
Marketing Pipeline Elimina-
Activities Operations tions Total
---------- ---------- --------- -------
1998
Operating revenues................... $ 8,352 $2,175 $ 6 $10,533
Equity in earnings of affiliates..... 114 3 -- 117
------- ------ ---- -------
Total operating revenues............. 8,466 2,178 6 10,650
Depreciation and amortization........ 60 104 3 167
Interest expense..................... 54 96 6 156
Income tax (benefit) expense......... 33 5 3 41
Income (loss) from continuing
operations.......................... 35 (11) (21) 3
Capital expenditures................. 96 88 37 221
Total assets at year-end............. 5,992 3,824 331 10,147
1999
Operating revenues................... 10,549 1,391 17 11,957
Equity in earnings of affiliates..... 63 -- -- 63
------- ------ ---- -------
Total operating revenues............. 10,612 1,391 17 12,020
Depreciation and amortization........ 98 116 -- 214
Interest expense..................... 67 96 (1) 162
Income tax (benefit) expense......... 18 (353) (16) (351)
Income (loss) from continuing
operations.......................... 22 (847) 35 (790)
Capital expenditures................. 84 49 17 150
Total assets at year-end............. 5,358 2,377 331 8,066
2000
Operating revenues................... 15,842 1,112 (24) 16,930
Equity in earnings of affiliates..... 65 -- -- 65
------- ------ ---- -------
Total operating revenues............. 15,907 1,112 (24) 16,995
Depreciation and amortization........ 102 41 -- 143
Interest expense..................... 64 90 1 155
Income tax (benefit) expense......... 97 37 (4) 130
Income (loss) from continuing
operations.......................... 104 78 10 192
Capital expenditures................. 297 15 -- 312
Total assets at year-end............. 11,558 1,204 344 13,106
F-42
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Integrated
Energy and Interstate Other and
Marketing Pipeline Elimina-
Activities Operations tions Total
---------- ---------- --------- -------
Six Months Ended June 30, 2000
(unaudited)
Operating revenues.................... $ 6,093 $ 562 $ 1 $ 6,656
Equity in earnings of affiliates...... 37 -- -- 37
------- ------ ---- -------
Total operating revenues.............. 6,130 562 1 6,693
Net income ........................... 56 27 1 84
Total assets at June 30, 2000......... 7,283 2,362 315 9,960
Six Months Ended June 30, 2001
(unaudited)
Operating revenues.................... 6,782 129 4 6,915
Equity in earnings of affiliates...... 49 -- -- 49
------- ------ ---- -------
Total operating revenues.............. 6,831 129 4 6,964
Net income ........................... 88 38 (1) 125
Total assets at June 30, 2001......... 10,310 1,172 475 11,957
F-43
[BACK COVER PAGE TO BE BLANK]
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers.
Section l45(a) of the Delaware General Corporation Law (the "DGCL") provides
that a Delaware corporation shall have the power to indemnify any person who
was or is a party, or is threatened to be made a party, to any threatened,
pending or completed action, suit or proceeding, whether civil, criminal,
administrative or investigative, other than any action by or in the right of
the corporation, by reason of the fact that the person is or was a director,
officer, employee or agent of the corporation, or was serving at the request of
the corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other enterprise, against
expenses, including attorneys' fees, judgments, fines and amounts paid in
settlement actually and reasonably incurred by the person in connection with
such action, suit or proceeding, if the person acted in good faith and in a
manner the person reasonably believed to be in, or not opposed to, the best
interests of the corporation, and, with respect to any criminal action or
proceeding, had no cause to believe the person's conduct was unlawful. In
addition, Section 145 (b) of the DGCL provides that a Delaware corporation may
similarly indemnify any person who was or is a party, or is threatened to be
made a party, to any threatened, pending, or completed action or suit by or in
the right of the corporation to procure a judgment in its favor by reason of
the fact that such person acted in any of the capacities set forth above,
against expenses actually and reasonably incurred by her or him, including
attorneys' fees, in connection with the defense or settlement of any action or
suit if the person acted in good faith and in a manner the person reasonably
believed to be in, or not opposed to, the best interests of the corporation,
except that no indemnification may be made in respect of any claim, issue or
matter as to which such person shall have been adjudged to be liable to the
corporation unless, and only to the extent that, the court in which such action
or suit was brought determines upon application that, in view of all of the
circumstances of the case, such person is fairly and reasonably entitled to be
indemnified for such expenses which the court shall deem proper. Section 145 of
the DGCL provides to the extent a director or officer of a corporation has been
successful in the defense of any action, suit or proceeding referred to in
subsections (a) and (b) of Section 145 or in the defense of any claim, issue,
or matter therein, the person shall be indemnified against any expenses
actually and reasonably incurred by her or him in connection therewith; (ii)
indemnification provided for by Section 145 shall not be deemed exclusive of
any rights to which the indemnified party may be entitled; and (iii) the
corporation may purchase and maintain insurance on behalf of a director or
officer of the corporation against any liability asserted against him or
incurred by him in any capacity or arising out of his status as such whether or
not the corporation would have the power to indemnify him against such
liabilities under Section 145.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation
of a corporation may contain provisions eliminating or limiting the personal
liability of a director to the corporation or its stockholders for monetary
damages for breach of fiduciary duty as a director. However, no such provisions
may eliminate or limit the liability of a director for (i) breaching of the
director's duty of loyalty to the corporation or its stockholders, (ii) failing
to act in good faith, engaging in intentional misconduct or knowingly violating
a law, (iii) paying a dividend or approving a stock repurchase which was
illegal, or (iv) obtaining an improper personal benefit from any transaction.
Provisions of this type have no effect on the availability of equitable
remedies, such as injunction or rescission, for breach of fiduciary duty. In
addition, these provisions will not limit the liability of directors and
officers under the federal securities laws of the United States. Our
certificate of incorporation contains such provisions.
Our by-laws provide that we shall indemnify any officer or director who was
or is a party, or is threatened to be made a party, to any threatened, pending
or completed action, suit or proceeding to the full extent permitted by law.
The by-laws further provide that we shall reimburse any director or officer for
expenses, including attorneys' fees, incurred by her or him in defending any
civil, criminal, administrative or investigative action, suit or proceeding to
the extent that such director or officer is successful on the merits in defense
of any such action. Additionally, the by-laws provide that we shall pay
expenses incurred in advance of
II-1
the final disposition of such action, suit or proceeding upon receipt of an
undertaking by or on behalf of such director or officer to repay such expenses
if it is ultimately determined that such director or officer is not entitled to
be indemnified by us against such expenses.
Item 21. Exhibits.
(a) Exhibits.
Number Description
------ -----------
3.1 Certificate of Incorporation of PG&E National Energy Group, Inc., as
amended.*
3.2 By-laws of PG&E National Energy Group, Inc. as amended and restated
March 1, 2001.*
4.1 Registration Rights Agreement dated as of May 22, 2001 between PG&E
National Energy Group, Inc. and Lehman Brothers Inc., as representative
for the initial purchasers of the 10.375% Senior Notes due 2011.*
4.2 Indenture dated as of May 22, 2001 between PG&E National Energy Group,
Inc. and Wilmington Trust Company, as Trustee.*
4.3 Form of exchange notes.*
5.1 Opinion of Orrick, Herrington & Sutcliffe LLP regarding the legality of
the exchange notes to be issued.*
10.1 Stock Purchase Agreement By and Between PG&E National Energy Group,
Inc. and El Paso Field Services Company, dated as of January 27, 2000
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 1999 (File No. 1-12609), Exhibit No. 10.1).
10.2 Description of Compensation Arrangement between PG&E Corporation and
Thomas G. Boren (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended September 30, 1999 (File No. 1-12609),
Exhibit 10.2).
10.3 Letter regarding Compensation Arrangement between PG&E Corporation and
Thomas B. King dated November 4, 1998 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File
No. 1-12609), Exhibit 10.6).
10.4 Letter regarding Compensation Arrangement between PG&E Corporation and
Lyn E. Maddox dated April 25, 1997 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.7).
10.5 Letter Regarding Relocation Arrangement Between PG&E Corporation and
Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E
Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No.
1-12609), Exhibit 10).
10.6 Description of Relocation Arrangement Between PG&E Corporation and Lyn
E. Maddox (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9).
10.7 Letter regarding retention award to Thomas G. Boren dated February 27,
2001 (incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.11).
10.8 Letter regarding retention award to Lyn E. Maddox dated February 27,
2001 (incorporated by reference to PG&E Corporation's 10-K for the year
ended December 31, 2000 (File No. 1-12609),
Exhibit 10.10.12).
10.9 Letter regarding retention award to P. Chrisman Iribe dated February
27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for
the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13).
II-2
Number Description
------ -----------
10.10 Letter regarding retention award to Thomas B. King dated February 27,
2001 (incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14).
10.11 Letter regarding retention award to Sarah M. Barpoulis dated February
27, 2001.*
10.12 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2000
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.7).
10.13 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2001
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.14).
10.14 PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001,
including the PG&E Corporation Stock Option Plan, Performance Unit
Plan, and Non-Employee Director Stock Incentive Plan.*
10.15 PG&E Corporation Executive Stock Ownership Program, amended as of
September 19, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.20).
10.16 PG&E Corporation Officer Severance Policy, amended as of July 21, 1999
(incorporated by reference to PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1).
10.17 PG&E Corporation Supplemental Retirement Savings Plan dated as of
January 1, 2000 (incorporated by reference to PG&E Corporation's Form
10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit
10.2).
10.18 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporation's Form 10-Q for the
quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2).
10.19 Second Amended and Restated Wholesale Standard Offer Service Agreement
between the Narragansett Electric Company and USGen New England, Inc.,
dated as of September 1, 1998.*
10.20 Second Amended and Restated Wholesale Standard Offer Service Agreement
among Massachusetts Electric Company, Nantucket Electric Company and
USGen New England, Inc., dated as of September 1, 1998.*
10.21 Credit Agreement among PG&E National Energy Group, Inc., The Chase
Manhattan Bank and the several lenders dated as of June 15, 2001
(certain schedules and exhibits omitted).
12.1 Statement re Computation of Ratios.
21.1 Subsidiaries of PG&E National Energy Group, Inc.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of Orrick, Herrington & Sutcliffe LLP (included in Exhibit
5.1).*
25.1 Form T-1 Statement of Eligibility under Trust Indenture Act of 1939 of
Wilmington Trust Company.*
99.1 Form of Exchange Agency Agreement.*
99.2 Form of Letter of Transmittal.*
99.3 Form of Notice of Guaranteed Delivery.*
99.4 Form of Letter to Clients.*
99.5 Form of Letter to Nominees.*
- --------
* Previously filed.
(b) Financial Statement Schedules.
Schedule II--Consolidated Valuation and Qualifying Accounts.
Schedules not listed above have been omitted because the information
required to be set forth therein is not applicable or is shown in the financial
statements or notes thereto.
II-3
Item 22. Undertakings.
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the Securities
Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after the
effective date of the registration statement (or the most recent post-effective
amendment thereof) which, individually or in the aggregate, represent a
fundamental change in the information set forth in the registration statement.
Notwithstanding the foregoing, any increase or decrease in volume of securities
offered (if the total dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high end of the
estimated maximum offering range may be reflected in the form of prospectus
filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the
changes in volume and price represent no more than a 20% change in the maximum
aggregate offering price set forth in the "Calculation of Registration Fee"
table in the effective registration statement;
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement.
(2) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination of
the offering.
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 Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted 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 and will be governed
by the final adjudication of such issue.
The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means. This includes information contained in documents
filed subsequent to the effective date of the registration statement through
the date of responding to the request.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act, the registrant has duly
caused this amendment to registration statement to be signed on its behalf by
the undersigned, thereunto duly authorized, in the city of Bethesda, state of
Maryland, on August 20, 2001.
PG&E National Energy Group, Inc.
(Registrant)
/s/ Thomas G. Boren
By: _________________________________
Thomas G. Boren
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Act of 1933, this amendment
to registration statement has been signed by the following persons in the
capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Thomas G. Boren Director, President and August 20, 2001
____________________________________ Chief Executive Officer
Thomas G. Boren (principal executive
officer)
/s/ John R. Cooper Senior Vice President, August 20, 2001
____________________________________ Finance (principal
John R. Cooper financial officer)
/s/ Thomas E. Legro Vice President, Controller August 20, 2001
____________________________________ and Chief Accounting
Thomas E. Legro Officer (principal
accounting officer)
____________________________________ Director
Peter A. Darbee
/s/ G. Brent Stanley Director August 20, 2001
____________________________________
G. Brent Stanley
/s/ Andrew L. Stidd Director August 20, 2001
____________________________________
Andrew L. Stidd
/s/ Bruce R. Worthington Director August 20, 2001
____________________________________
Bruce R. Worthington
II-5
PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2000, 1999 and 1998
(in millions)
Column A Column B Column C Column D Column E
-------- ---------- Additions ---------- ---------
-------------------
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Period Expenses Accounts Deductions of Period
----------- ---------- ---------- -------- ---------- ---------
Valuation and qualifying
accounts deducted from
assets:
2000:
Allowance for
uncollectible
accounts(1)............ $19 $12 -- $12 $19
1999:
Allowance for
uncollectible
accounts(1)............ $17 $ 8 -- $ 6 $19
1998:
Allowance for
uncollectible
accounts(1)............ $15 $ 4 -- $ 2 $17
- --------
(1) The allowance for uncollectible accounts is deducted from "accounts
receivable, trade" in the consolidated balance sheet. Deductions consist
principally of write-offs, net of collections of accounts receivable
previously written off.
Exhibit Index
Number Description
------ -----------
3.1 Certificate of Incorporation of PG&E National Energy Group, Inc., as
amended.*
3.2 By-laws of PG&E National Energy Group, Inc. as amended and restated
March 1, 2001.*
4.1 Registration Rights Agreement dated as of May 22, 2001 between PG&E
National Energy Group, Inc. and Lehman Brothers Inc., as representative
for the initial purchasers of the 10.375% Senior Notes due 2011.*
4.2 Indenture dated as of May 22, 2001 between PG&E National Energy Group,
Inc. and Wilmington Trust Company, as Trustee.*
4.3 Form of exchange notes.*
5.1 Opinion of Orrick, Herrington & Sutcliffe LLP regarding the legality of
the exchange notes to be issued.*
10.1 Stock Purchase Agreement By and Between PG&E National Energy Group,
Inc. and El Paso Field Services Company, dated as of January 27, 2000
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 1999 (File No. 1-12609), Exhibit No. 10.1).
10.2 Description of Compensation Arrangement between PG&E Corporation and
Thomas G. Boren (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended September 30, 1999 (File No. 1-12609),
Exhibit 10.2).
10.3 Letter regarding Compensation Arrangement between PG&E Corporation and
Thomas B. King dated November 4, 1998 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File
No. 1-12609), Exhibit 10.6).
10.4 Letter regarding Compensation Arrangement between PG&E Corporation and
Lyn E. Maddox dated April 25, 1997 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.7).
10.5 Letter Regarding Relocation Arrangement Between PG&E Corporation and
Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E
Corporation's Form 10-Q for the quarter ended March 31, 2000 (File No.
1-12609), Exhibit 10).
10.6 Description of Relocation Arrangement Between PG&E Corporation and Lyn
E. Maddox (incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.9).
10.7 Letter regarding retention award to Thomas G. Boren dated February 27,
2001 (incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.11).
10.8 Letter regarding retention award to Lyn E. Maddox dated February 27,
2001 (incorporated by reference to PG&E Corporation's 10-K for the year
ended December 31, 2000 (File No. 1-12609),
Exhibit 10.10.12).
10.9 Letter regarding retention award to P. Chrisman Iribe dated February
27, 2001 (incorporated by reference to PG&E Corporation's Form 10-K for
the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.13).
10.10 Letter regarding retention award to Thomas B. King dated February 27,
2001 (incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.14).
10.11 Letter regarding retention award to Sarah M. Barpoulis dated February
27, 2001.*
Number Description
------ -----------
10.12 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2000
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.7).
10.13 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2001
(incorporated by reference to PG&E Corporation's Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.14).
10.14 PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001,
including the PG&E Corporation Stock Option Plan, Performance Unit
Plan, and Non-Employee Director Stock Incentive Plan.*
10.15 PG&E Corporation Executive Stock Ownership Program, amended as of
September 19, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.20).
10.16 PG&E Corporation Officer Severance Policy, amended as of July 21, 1999
(incorporated by reference to PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1).
10.17 PG&E Corporation Supplemental Retirement Savings Plan dated as of
January 1, 2000 (incorporated by reference to PG&E Corporation's Form
10-K for the year ended December 31, 1999 (File No. 1-12609), Exhibit
10.2).
10.18 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporation's Form 10-Q for the
quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2).
10.19 Second Amended and Restated Wholesale Standard Offer Service Agreement
between the Narragansett Electric Company and USGen New England, Inc.,
dated as of September 1, 1998.*
10.20 Second Amended and Restated Wholesale Standard Offer Service Agreement
among Massachusetts Electric Company, Nantucket Electric Company and
USGen New England, Inc., dated as of September 1, 1998.*
10.21 Credit Agreement among PG&E National Energy Group, Inc., The Chase
Manhattan Bank and the several lenders dated as of June 15, 2001
(certain schedules and exhibits omitted).
12.1 Statement re Computation of Ratios.
21.1 Subsidiaries of PG&E National Energy Group, Inc.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of Orrick, Herrington & Sutcliffe LLP (included in Exhibit
5.1).*
25.1 Form T-1 Statement of Eligibility under Trust Indenture Act of 1939 of
Wilmington Trust Company.*
99.1 Form of Exchange Agency Agreement.*
99.2 Form of Letter of Transmittal.*
99.3 Form of Notice of Guaranteed Delivery.*
99.4 Form of Letter to Clients.*
99.5 Form of Letter to Nominees.*
- --------
* Previously filed.