Exhibit 99
Information Regarding PG&E National Energy Group, Inc.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This document includes forward-looking statements relating to PG&E National
Energy Group, Inc. In this document, references to "we," "our," "ours" and "us"
refer only to PG&E National Energy Group, Inc. and to its direct or indirect
subsidiaries or affiliates as the context requires. We have based these
forward-looking statements on our current expectations and projections about
future events based upon our knowledge of facts as of May 3, 2001 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;
. 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.
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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 document.
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
document, 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.
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RISK FACTORS
The risks described in this section are those that we consider to be the
most significant to our business, financial condition or results of operations.
If any of these events occur, our business, financial condition or results of
operations could be materially harmed.
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
combinations. 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 that 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;
. 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 certain of our subsidiaries' material agreements, which default
could lead to the downgrading of our credit ratings.
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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.
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.
Claims could be made in the Pacific Gas and Electric Company bankruptcy case
that we are the recipients of certain fraudulent transfers; any such claim, if
successful, could have a material adverse effect on us.
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 approximately $250 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 made to us by
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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 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.
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, including Pacific Gas and Electric Company, 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
. the holding companies' actions to "ringfence" their unregulated
subsidiaries.
While we are not a party to this action by the CPUC, nor are we regulated by
the CPUC, we cannot assure you that we would be effectively insulated from such
proceedings. To the extent the CPUC's action involves us in any way, including
with respect to the above noted issues, we are unable to predict the impact
such action might have on us either directly or indirectly.
If we do not replace PG&E Corporation credit support for certain of our master
turbine trusts, the lenders could exercise remedies that may adversely impact
our growth strategy.
Currently, PG&E Corporation provides credit support for our two master
turbine trusts in the form of equity infusion agreements. These master turbine
trusts require that PG&E Corporation maintain at least an investment grade
rating. Although we have also guaranteed outstanding draws under these master
turbine trusts, as a result of PG&E Corporation's recent credit downgrade, we
must replace PG&E Corporation's credit support for these master turbine trusts
with guarantees from us or alternative collateral acceptable to the lenders. We
expect to complete a release of these PG&E Corporation equity infusion
agreements by July 2, 2001. However, if we are unable to do so because the
lenders will not accept our guarantees or alternative collateral, the financing
arrangements for the master turbine trusts may be in default and the lenders
could exercise a number of remedies, including foreclosing on their security,
refusing to fund further draws and accelerating the repayment of any
outstanding borrowings. The exercise of any of these remedies could have an
adverse impact on our growth strategy. In addition, the failure to replace
these equity infusion agreements by July 2, 2001 is an event of default under
PG&E Corporation's $1 billion credit agreement.
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.
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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.
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. 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 an 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, as applicable.
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 December 31, 2000, our consolidated subsidiaries had aggregate
indebtedness of approximately $2.2 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.
We have a substantial amount of indebtedness, including a substantial amount of
short-term indebtedness, which indebtedness could limit our ability to finance
the acquisition and development of additional projects.
As of December 31, 2000, we had short-term debt of $828 million (including
debt to PG&E Corporation) and long-term borrowings of $1.4 billion (excluding
the debt of project affiliates accounted for under the equity method). Our
substantial amount of debt and financial obligations presents the risk that we
might not have sufficient cash to service our indebtedness 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.
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We maintain various revolving credit facilities at subsidiary levels which
currently are available to fund our capital and liquidity needs. Our generation
operation maintains two revolving credit facilities of $550 million each and
one $100 million revolving credit facility. One of the $550 million facilities
expires in August 2001 (but may be extended for up to two years) and the other
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), and a 364-day $50
million revolving credit facility that expires on May 21, 2001. As of April 30,
2001, there were no loans outstanding under the $50 million revolving credit
facility. As of December 31, 2000, we had borrowed $1.18 billion against our
total $1.35 billion borrowing capacity under these facilities. In addition,
approximately $37 million of letters of credit were outstanding under these
facilities, reducing the remaining borrowing capacity available.
We are in the process of arranging a revolving credit facility of up to $280
million that we will guarantee to fund turbine payments and equipment purchases
associated with the development of our generation facilities. Borrowings from
this facility will be used to purchase all turbines from our two master turbine
trusts. We also are in the process of arranging a $500 million facility to
support the issuance of letters of credit to support our trading operations and
other working capital requirements. We are planning, by the end of 2001, to
replace this facility and the two $550 million facilities at our generation
operation with a $1.25 billion unsecured revolving credit facility that will be
a senior obligation of PG&E National Energy Group, Inc. We expect this facility
to have a portion with a 364-day term and a portion with a term of two to three
years.
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 meet our financial obligations.
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 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 needed to generate
the electricity that we sell. 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;
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. 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 April 9, 2001.
Although our credit ratings remain investment grade, the downgrading of our
credit ratings below investment grade could 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 on Lake Road, La Paloma, Harquahala, the master turbine
trusts and the additional senior indebtedness that we expect to incur, if we
were downgraded below investment grade, we would be in default, as a result of
which we would be required to provide alternative credit enhancements, such as
other investment grade guarantees, letters of credit or cash collateral. If we
were unable to provide such enhancements, the lenders to those projects would
have the right to stop lending under the applicable financing agreement,
foreclose on the project assets, accelerate the maturities of the loans 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, 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.
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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 meet our financial obligations 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, 12 of our 20 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.
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
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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.
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 turbines installed
in our Millennium facility that delayed the commercial operation of this
facility, until April 2001.
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. 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 on the
amount that can be charged by electricity generators in particular markets,
such as the price caps recently approved in California. Certain states, for
example New York and California, also have proposed such price caps. These
types of initiatives could have an adverse impact on our financial performance
if, for example, they result in substantially higher transmission costs than
expected or prevent us from achieving our projected financial results.
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
10
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 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
11
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.
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 2008.
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;
12
. 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;
. 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 and Marketing. 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 increased employee attrition.
13
CAPITALIZATION
The following table sets forth our capitalization as of December 31, 2000.
Our capitalization is presented on an actual basis.
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 document.
As of
December 31, 2000
Actual
-----------------
(in millions)
Current portion of long-term debt............................. $ 17
Short-term borrowings(1)...................................... 519
Short-term debt--parent....................................... 309
------
Total short-term debt....................................... 845
Total long-term debt........................................ 1,390
Preferred stock of subsidiary................................. 57
Minority equity interests..................................... 18
Common stockholder's equity................................... 2,304
------
Total capitalization.......................................... $4,614
======
- --------
(1) We have the option to defer the repayment of the short-term borrowings for
two years.
14
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 for the years ended December 31, 1996 and 1997, 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 document.
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 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
connection with the acquisition, we further agreed to provide
electricity to certain retail providers in New England at predetermined
rates. In return for our assumption of these power supply 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 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 market
potential for retail energy services, we decided in December 1999 to
sell this business and
15
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.
Year Ended December 31,
----------------------------------------------------
1996 1997 1998 1999 2000
----------- ----------- ----------- ------- -------
(unaudited) (unaudited)
(in millions)
Income Statement Data:
Operating revenues....... $ 426 $6,101 $10,650 $12,020 $16,995
Impairments and write-
offs.................... 60 87 -- 1,275 --
Other operating
expenses................ 306 6,081 10,488 11,851 16,604
------ ------ ------- ------- -------
Total operating
expenses............... 366 6,168 10,488 13,126 16,604
------ ------ ------- ------- -------
Operating income (loss).. 60 (67) 162 (1,106) 391
Other income (expense):
Interest income......... 18 29 45 75 80
Interest expense........ (46) (81) (156) (162) (155)
Other, net.............. 6 119 (7) 52 6
------ ------ ------- ------- -------
Income (loss) from
continuing operations
before income taxes..... 38 -- 44 (1,141) 322
Income tax expense
(benefit)............... 30 (32) 41 (351) 130
------ ------ ------- ------- -------
Income (loss) from
continuing operations... 8 32 3 (790) 192
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
Cumulative effect of a
change in accounting
principle, net of income
taxes................... -- -- -- 12 --
------ ------ ------- ------- -------
Net income (loss)........ $ 8 $ 4 $ (54) $ (883) $ 152
====== ====== ======= ======= =======
As of December 31,
----------------------------------------------------
1996 1997 1998 1999 2000
----------- ----------- ----------- ------- -------
(unaudited) (unaudited) (unaudited)
(in millions)
Balance Sheet Data:
Cash and cash
equivalents............. $ 149 $ 301 $ 168 $ 228 $ 738
Price risk management
assets, current......... 17 500 1,416 389 2,039
Other current assets..... 585 1,426 1,161 1,508 3,343
------ ------ ------- ------- -------
Total current assets.... 751 2,227 2,745 2,125 6,120
------ ------ ------- ------- -------
Property, plant and
equipment, net.......... 1,220 3,215 4,962 4,054 3,640
Investments in
affiliates.............. 701 587 572 530 417
Price risk management
assets, noncurrent...... -- 58 334 319 2,026
Other noncurrent assets.. 189 791 1,534 1,038 903
------ ------ ------- ------- -------
Total assets............ $2,861 $6,878 $10,147 $ 8,066 $13,106
====== ====== ======= ======= =======
Short-term borrowings.... $ -- $ 100 $ 293 $ 524 $ 519
Price risk management
liabilities, current.... -- 476 1,412 323 1,999
Other current
liabilities............. 505 1,456 1,173 1,549 3,315
------ ------ ------- ------- -------
Total current
liabilities............ 505 2,032 2,878 2,396 5,833
------ ------ ------- ------- -------
Long-term debt........... 715 1,563 1,955 1,805 1,390
Price risk management
liabilities,
noncurrent.............. 0 46 281 207 1,867
Other long-term
liabilities............. 409 848 2,233 1,776 1,637
------ ------ ------- ------- -------
Total liabilities....... 1,629 4,489 7,347 6,184 10,727
------ ------ ------- ------- -------
Preferred stock of
subsidiary and minority
interests............... 92 96 81 78 75
Stockholder's equity..... 1,140 2,293 2,719 1,804 2,304
------ ------ ------- ------- -------
Total liabilities and
stockholder's equity... $2,861 $6,878 $10,147 $ 8,066 $13,106
====== ====== ======= ======= =======
Other Data (for the year
ended December 31):
EBITDA(1)................ $ 196 $ 267 $ 322 $ 396 $ 526
Ratio of earnings to
fixed charges(2)........ 1.3 1.1 1.0 Note 3 2.2
16
- --------
(1) 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. EBITDA excludes non-
cash impairment charges and write-offs. EBITDA also includes all cash
offset payments from NEP related to our assumption of the purchase
obligations under power supply agreements in our 1998 acquisition of our
New England generating facilities. 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 EBITDA is a
standard measure commonly reported and widely used by analysts, investors
and other interested parties. However, EBITDA as presented herein may not
be comparable to similarly titled measures reported by other companies.
EBITDA is composed of the following items (in millions):
Year Ended December 31,
------------------------------
1996 1997 1998 1999 2000
---- ---- ---- ------ -----
Income (loss) from continuing operations.... $ 8 $ 32 $ 3 $ (790) $ 192
Add:
Income tax expense (benefit)............... 30 (32) 41 (351) 130
Depreciation and amortization expense...... 52 99 167 214 143
Interest expense........................... 46 81 156 162 155
Impairments and write-offs................. 60 87 0 1,275 0
Amortization of out-of-market contractual
obligations............................... 0 0 (65) (181) (163)
Cash offset payments related to NEP power
supply agreements......................... 0 0 20 67 69
---- ---- ---- ------ -----
EBITDA as defined.......................... $196 $267 $322 $ 396 $ 526
==== ==== ==== ====== =====
(2) 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.
(3) 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.
17
First Quarter of 2001--Capsule Financial Information
For the three months ended March 31, 2001, our operating revenues were
approximately $4.2 billion, our net income was approximately $54 million and
our EBITDA was approximately $134 million.
In our integrated energy and marketing segment, operating revenues were
approximately $4.1 billion in the first quarter of 2001, net income was
approximately $35 million and EBITDA was approximately $84 million. These
results reflect increased margins from our merchant generating facilities, due
primarily to higher electricity prices in the northeast, and from our energy
trading activities, reflecting generally higher prices throughout U.S. energy
markets.
Operating revenues in our interstate pipeline operations segment were
approximately $65 million in the first quarter of 2001, net income was
approximately $20 million and EBITDA was approximately $53 million. These
results reflect high capacity load factors and improved pricing fundamentals in
western gas markets, together improving short-term firm revenues for our GTN
pipeline.
The following table presents summary historical financial data for the three
months ended March 31, 2001. This financial information is derived from our
unaudited financial statements and may not be indicative of our future
performance.
Three Months Ended
March 31, 2001
------------------------
(in millions, unaudited)
Operating revenues
Integrated energy and marketing.................. $4,152
Interstate pipeline operations................... 65
Eliminations and other........................... (9)
------
Total operating revenues.......................... $4,208
======
Net income
Integrated energy and marketing.................. $ 35
Interstate pipeline operations................... 20
Eliminations and other........................... (1)
------
Total net income.................................. $ 54
======
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with "Risk Factors,"
"Selected Consolidated Financial Data" and our consolidated financial
statements and related notes included elsewhere in this document.
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.
The following table sets forth the operating revenues and income from
continuing operations attributable to each of our operating segments:
Year Ended December 31,
-------------------------
1998 1999 2000
------- ------- -------
(in millions)
Operating revenues
Integrated energy and marketing................. $ 8,466 $10,612 $15,907
Interstate pipeline operations
GTN........................................... 237 243 239
GTT........................................... 1,941 1,148 873
Eliminations and other.......................... 6 17 (24)
------- ------- -------
Total operating revenues.......................... $10,650 $12,020 $16,995
======= ======= =======
Income from continuing operations
Integrated energy and marketing................. $ 35 $ 22 $ 104
Interstate pipeline operations
GTN........................................... 60 61 58
GTT........................................... (71) (908) 20
Eliminations and other.......................... (21) 35 10
------- ------- -------
Total income from continuing operations........... $ 3 $ (790) $ 192
======= ======= =======
We account for our business in two reportable segments, integrated energy
and marketing, or energy, and interstate pipeline operations, or pipeline. 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. Income from continuing operations
contributed by these activities was $13 million in 2000 and negligible in 1999
and 1998.
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
19
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.
We currently sell approximately 82% 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. It also includes 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 generally are required to pay
to PG&E Corporation the amount of income taxes that we would record if we filed
our own consolidated combined or unitary return separate from PG&E Corporation.
These changes would not have affected our net income or total assets in 1998,
1999 or 2000.
Results of Operations
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.
20
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 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
pending 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.
21
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.
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.
22
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 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 somewhat. 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 that we enter into.
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
operations including distributions and fees from subsidiaries. In many cases,
the loan, partnership and other agreements that apply to our subsidiaries and
project affiliates restrict these projects 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 and unless the subsidiary has either
an 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, as applicable.
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 rate
from January 1, 2001. As of December 31, 2000, we had a net outstanding loan
balance payable to PG&E Corporation of $234 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 collateral for a
range of our contractual commitments. With respect to our generating
facilities, this collateral has included agreements to infuse equity
23
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 April 30, 2001, except
for $153 million of guarantees under various energy trading contracts and $314
million in equity infusion agreements, we have replaced all other PG&E
Corporation equity infusion agreements and guarantees with our own equity
infusion agreements, guarantees or other forms of security. Under the credit
agreement governing its $1 billion term loan, PG&E Corporation is 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. We are in discussions with our trading counterparties and lenders and
expect to replace the balance of the PG&E Corporation equity infusion
agreements and guarantees. While we expect to satisfy these requirements by
July 2, 2001, our inability to meet them would result in a default by PG&E
Corporation which could result in acceleration of those loans and foreclosure
by the lenders on our stock or the LLC membership interests.
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 the LLC unless our board of directors, including our independent
director, unanimously approves and unless we have either an investment grade
credit rating or meet a 2.25 to 1.00 consolidated interest coverage ratio and a
0.70 to 1.00 consolidated leverage ratio, as applicable.
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 $226
million as of March 31, 2001. We are in the process of arranging with a
syndicate of banks a $500 million revolving credit facility to support our
energy trading operations and for other working capital requirements. We expect
this facility to be in place by the end of May 2001.
We are in the process of arranging a revolving credit facility of up to $280
million that we will guarantee and which we expect to be in place by July 2,
2001. This facility will fund turbine payments and equipment purchases
associated with the development of our generation facilities. Borrowings from
this facility will be used to purchase all turbines from our two master turbine
trusts. The master turbine trusts were originally created to own and facilitate
development, construction financing and leasing of turbine-powered generating
facilities.
We also maintain various revolving credit facilities at subsidiary levels
which currently are available to fund our capital and liquidity needs. Our
generation operation maintains two revolving credit facilities of $550 million
each and one $100 million revolving credit facility. One of the $550 million
facilities, a 364-day facility, expires in August 2001 (but may be extended for
up to two years), and the other, 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 two successive one-year periods), and a 364-day $50 million revolving
credit facility that expires on May 21, 2001, but may be converted to a two-
year term loan at our option. As of April 30, 2001, there were no loans
outstanding under the $50 million revolving credit facility. Outstanding loans
on all five 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 five 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 December 31, 2000, we
had borrowed $1.18 billion against our total $1.35 billion borrowing capacity
under these facilities. In addition, approximately $37 million of letters of
credit were outstanding under these facilities.
We are planning to replace by the end of 2001 our new $500 million facility
and the two $550 million facilities at our generation operation with a $1.25
billion unsecured revolving credit facility that will be a senior
24
obligation of PG&E National Energy Group, Inc. We expect this facility will
have a portion with a 364-day term and a portion with a term of two to three
years.
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;
. increase 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;
. increase our use of 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. Options we
are currently evaluating for raising additional equity include an initial
public offering, the issuance of debt, 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.
If our credit rating were downgraded below investment grade, we would be in
default under various guarantees that we have provided, including guarantees
for Lake Road, La Paloma, Harquahala, the master turbine trusts, and senior
indebtedness we expect to incur, as a result of which we would be required to
provide alternative credit enhancements such as other investment grade
guarantees, letters of credit or cash collateral. If we were unable to provide
such enhancements, the lenders to those projects would have the right to stop
lending under the applicable financing agreements, foreclose on the project
assets, accelerate the maturities of the loans and call on our guarantees. If
we were unable to perform under these guarantees, we could be in a default
under all of our senior obligations, 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
25
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.
Generating Projects in Construction
We currently own, control, or will own the output of six generating
facilities under construction: Lake Road, La Paloma, Attala, Mountain View,
Ohio Peakers 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 three-year operating lease for the projects will begin. Our
obligations under these leases will be determined at the completion of
construction and are estimated to begin in 2001 (for Lake Road) and 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.
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 is obligated to complete construction and
deliver a fully operational facility to us by July 1, 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 at completion
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 are financing the expected $47 million in total costs of Ohio Peakers
under our revolving credit facilities. 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 quarter of 2001. We expect to finance this purchase from
the net proceeds of a debt offering, with available cash or amounts drawn under
our revolving credit facilities. Finally, under our tolling agreement for
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.
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 19,708 MW of net generating capacity. Ten of
these turbines, representing approximately 2,821 MW, are for generating
facilities under construction or recently placed in operation as of April 30,
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 have
committed to provide up to $314 million in equity to meet our obligations to
the trusts. As of March 31, 2001, the trusts had incurred $202 million of
expenditures. We currently are arranging a revolving credit facility of up to
$280 million which will also be used to finance our ongoing equipment payment
obligations. In connection
26
with the implementation of this facility, we also expect to provide guarantees
to equipment vendors in an aggregate amount in excess of $100 million. Once
implemented, we plan to use borrowings from the facility to buy the turbines
from the trusts and heat-recovery steam generators, steam turbines and
transformers from Hitachi. We will then terminate the $314 million equity
commitment.
In addition, we have entered into agreements with a third 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 PG&E Corporation and us to
contribute up to $122 million in equity. As of March 31, 2001, the trust had
incurred $79 million of project-related expenditures. We are in the process of
arranging a multi-project financing facility that would provide construction
financing for Harquahala, Athens and one other project to be determined. 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 in the third quarter of 2001.
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. As of March 31, 2001, we had funded
payments totaling $146 million for Athens. We recently entered into an
agreement with Bechtel for the construction of the Athens facility. We have
guaranteed $70 million with respect to various Athens contractors, including
Bechtel, for certain pre-construction commitments.
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
March 31, 2001, our annual estimated committed payments under these contracts
ranged from $21 million to $339 million, resulting in total committed payments
over the next 28 years of approximately $6.5 billion. We provide guarantees
under each of these agreements and receive guarantees from our counterparties.
As of March 31, 2001, we have provided or committed to provide guarantees to
support these tolling agreements totaling up to $1,109 million. Our subsidiary
entered into a contract with SRW Cogen Limited Partnership in July 30, 1999
under which we would control 250 MW of a 420 MW cogeneration facility the
limited partnership is building and will operate. The limited partnership has
notified us of its purported termination of the contract as a result of the
downgrade of the debt of PG&E Corporation, the guarantor under this tolling
agreement. We are contesting the termination because we do not believe that the
conditions that would allow the limited partnership to terminate the contract
have been met.
In connection with the Southaven tolling agreement, we are in negotiations
and expect to provide to the owner of that project, a subsidiary of Cogentrix,
a commitment to provide up to $75 million of subordinated debt at the time of
completion of the project, if at that time we are not rated at least Baa2 by
Moody's or BBB by Standard & Poor's.
On December 6, 2000, we agreed to sell one of our development projects, Otay
Mesa, for a price of $33 million plus certain cost reimbursements and
contingent bonuses, subject to regulatory approval expected to be obtained in
the second quarter of 2001. At the same time, 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, also
subject to regulatory approval. 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.
27
Other Commitments and Plans
Our energy marketing and trading operation has a number of outstanding
commitments under various energy trading contracts, for which we or PG&E
Corporation have provided guarantees. As of April 30, 2001, the face value of
these guarantees totaled $2,715 million. Of this amount, we provided $2,562
million and PG&E Corporation provided $153 million. 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 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
(in
Year 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 Harquahala and Otay Mesa projects and will also support our La Paloma
facility. Under the terms of the agreement, our future minimum annual
commitments are $27 million per year from 2001 to 2005 and a total of $127
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, 200 million cubic feet per day, to be completed by the end of 2002
and to cost approximately $122 million. Depending on the results of an open
season we are about to initiate, we intend to complete a second phase of this
expansion for additional capacity, expected to range from 300 to 500 million
cubic feet per day. A 300 million cubic foot per day expansion would cost
approximately $322 million and could be completed as early as 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 a joint venture for the 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.
We anticipate spending up to approximately $330 million, net of insurance
proceeds, through 2008 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 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 and the 111 MW Plains End project in Colorado that are in the process
of construction
28
and advanced development, respectively. The unit also owns numerous used
turbines, which are in various stages of refurbishment. The dispersed
generation business unit had approximately $105 million of assets as of
December 31, 2000.
Operating 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 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.
Financing Activities
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 to PG&E Corporation a dividend of $151 million.
29
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, interest rate risk,
foreign currency risk, and equity risk. 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 established by our
board of directors. Both committees are comprised of senior executive officers.
Commodity Price Risk
Commodity price risk is the risk that changes in market prices will
adversely affect our earnings, value and cash flows. 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 all derivative and commodity investments in our trading
portfolio and only derivative commodity investments for our non-trading
portfolio (but not the related underlying hedged position). 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 December 31, 2000, 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 in 1998, 1999 and 2000 (in millions),
with Trading representing the combined results for all of our trading
operations:
Commodity
Price Type of
Risk 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 0.0 1.7
12/31/98 Trading 6.2 4.5 2.5 6.2
Non-Trading 0.2 not available not available not available
30
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 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 $9
million, based on variable rate debt and derivatives and other interest rate
sensitive instruments outstanding at December 31, 2000.
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 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 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, 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 December 31, 2000, 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 the 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
31
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 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 will not be reflected
on the balance sheet at fair value. The Derivatives Implementation Group of the
Financial Accounting Standards Board has reached a conclusion that, if adopted,
would change the definition of normal purchases and sales. As such, certain
derivative commodity contracts may no longer be exempt from the requirements of
SFAS No. 133. When the final decision regarding this issue is complete, we will
evaluate the impact of the implementation guidance on a prospective basis. We
continue to evaluate the impact of evolving authoritative accounting guidance,
including interpretations issued by the FASB's Derivatives Implementation
Group, on our financial statements.
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 adoption of SAB No. 101 did not have a material impact on the consolidated
financial statements.
32
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 April 30, 2001, we had ownership or
leasehold interests in 20 operating generating facilities with a net generating
capacity of 5,590 MW, as follows:
Number of Primary % of
Facilities Net MW Fuel Type Portfolio
---------- ------ ----------- ---------
10 2,997 Coal/Oil 54
6 1,415 Natural Gas 25
3 1,166 Water 21
1 12 Wind --
--- ----- ---
20 5,590 100
In addition, we have five facilities totaling 2,671 MW in construction, and we
control through various arrangements an additional 518 MW in operation and 780
MW in construction, giving us a total owned and controlled generating capacity
in operation or construction of 9,559 MW. We also own or control 12,620 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 22,179 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 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.
During 2000, 33% of our 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.
33
Strategy
During 2000, an estimated $227 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 9,675 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 7,323 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 4,243 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
the facility 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.
. Strategic Acquisitions. 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.
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.
34
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 9,675 MW of owned advanced
development projects 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.
. 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.
35
Proven Power Plant Developer. We have a successful track record of
greenfield development of generating facilities. Since 1991, we have placed 17
generating facilities in construction with a net generating capacity of 5,460
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.
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 17
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 6,108 MW produced by owned or controlled
power generating facilities operating in 12 states as of April 30, 2001. We
plan to increase our net beneficial interest in generating capacity primarily
through greenfield development of gas-fired generating facilities and
contractual control of generating capacity in targeted markets. In addition, we
own five facilities totaling 2,671 MW in construction, and control, through
various arrangements, an additional 1,298 MW in operation or construction
giving us total owned and controlled capacity in operation or construction of
9,559 MW. We also own or control 12,620 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 22,179 MW by the
end of 2004.
36
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 72% 5,741 59% 5,741 34% 5,741 26%
Mid-Atlantic and New
York................... 544 9% 544 7% 1,074 11% 3,051 18% 4,254 19%
Midwest................. 160 3% 304 4% 304 3% 2,644 16% 4,889 22%
South................... 261 5% 1,011 13% 1,011 11% 2,631 15% 2,631 12%
West.................... 242 4% 308 4% 1,540 16% 2,870 17% 4,664 21%
----- --- ----- --- ----- --- ------ --- ------ ---
Total................. 5,748 100% 7,908 100% 9,670 100% 16,937 100% 22,179 100%
===== === ===== === ===== === ====== === ====== ===
Dispatch Type
Merchant Plants
Baseload.............. 2,114 37% 4,079 52% 5,615 58% 12,465 74% 17,273 78%
Peaking/Intermediate.. 2,534 44% 2,729 34% 2,955 31% 3,372 20% 3,806 17%
Independent Power
Projects............... 1,100 19% 1,100 14% 1,100 11% 1,100 6% 1,100 5%
----- --- ----- --- ----- --- ------ --- ------ ---
Total................. 5,748 100% 7,908 100% 9,670 100% 16,937 100% 22,179 100%
===== === ===== === ===== === ====== === ====== ===
Fuel Type
Natural Gas............. 1,380 24% 3,474 44% 5,236 54% 12,503 74% 17,745 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% 7,908 100% 9,670 100% 16,937 100% 22,179 100%
===== === ===== === ===== === ====== === ====== ===
Ownership and Control
Owned/Leased............ 5,230 91% 7,140 90% 8,372 87% 13,769 81% 17,936 81%
Controlled Output....... 518 9% 768 10% 1,298 13% 3,168 19% 4,243 19%
----- --- ----- --- ----- --- ------ --- ------ ---
Total................. 5,748 100% 7,908 100% 9,670 100% 16,937 100% 22,179 100%
===== === ===== === ===== === ====== === ====== ===
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.
37
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
------------------------------------------------
Power 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;
. increase 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;
. increase our use of 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. Options we
are currently evaluating for raising additional equity include an initial
public offering, the issuance of debt, 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.
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;
38
. contractual control of generating capacity;
. energy marketing and trading; and
. risk management.
Ownership and Operation of Generating Facilities
As of April 30, 2001, we had ownership or leasehold interests in
20 operating generating facilities with a net generating capacity of 5,590 MW.
These facilities include six gas-fired generating facilities with a net
generating capacity of 1,415 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 17 of our 20 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 17 national and state 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
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.
39
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 1,100 MW in independent power
projects as of April 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 17 generating facilities in
construction with a net generating capacity of 5,460 MW. 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 five generating
facilities under construction in four states that will have a net generating
capacity of 2,671 MW. These projects are expected to be placed in
40
service in 2001 and 2002. 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 ten generating facilities in advanced development that are
expected to have a net generating capacity of 9,675 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 7,323 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 19,708 MW of net
generating capacity. Ten of these turbines, representing approximately 2,821
MW, are for generating facilities under construction or recently placed in
operation as of April 30, 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 cost
output and a 2% to 4% 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.
41
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
Generating
Quantity Capacity (1)
Manufacturer and Type of Turbines (MW)
--------------------- ----------- ------------
G Technology Turbines
Mitsubishi 501G Turbine........................... 21 8,322
Siemens Westinghouse 501G Turbine................. 7 2,520
Alstom GT24 Turbine............................... 7 1,961
F Technology Turbines
General Electric 7FB Turbine...................... 23 6,405
General Electric 7FA Turbine...................... 2 500
--- ------
Total........................................... 60 19,708
=== ======
- --------
(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 4,243 MW of generating
capacity, which result in control of 518 MW of operating generating capacity
and 3,725 MW of generating capacity in construction or development as of April
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 4,243 MW and
will do so if warranted.
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
42
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 seven tolling agreements we have entered into as of April
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 derivative financial instruments 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 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
43
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 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.
44
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
allow 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 a 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 who reports directly to the board of directors. 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 our trading transactions
through our state-of-the-art risk management software systems.
45
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 April 30, 2001:
Our Net
Interest Date of
Total in Total Primary Output Commercial
Generating Facility State MW MW(1) 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 NH/VT 484 484 Owned Water Competitive Market Operational 1909-1957
System..................
Masspower................ MA 267 35 Owned Natural Gas Power Purchase Operational 1993
Agreements
Pittsfield(2)............ MA 173 143 Leased Natural Gas Power Purchase Operational 1990
Agreements and
Competitive Market
Milford Power(2)......... 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(2)....... RI 69 69 Contract Natural Gas Competitive Market Operational 1991
14 smaller Various 193 193 Contract Renewable/ Competitive Market Operational Various
facilities(2)........... Waste
Millennium(3)............ 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
Selkirk.................. NY 345 145 Owned Natural Gas Power Purchase Operational 1992
Agreements and
Competitive Market
Carneys Point............ NJ 269 135 Owned Coal Power Purchase Operational 1994
Agreements
Logan.................... NJ 225 113 Owned Coal Power Purchase Operational 1994
Agreement
Northampton.............. PA 110 55 Owned Waste Coal Power Purchase Operational 1995
Agreements
Panther Creek............ PA 80 40 Owned Waste Coal Power Purchase Operational 1992
Agreement
Scrubgrass............... PA 87 44 Owned Waste Coal Power Purchase Operational 1993
Agreement
Madison.................. NY 12 12 Owned Wind Competitive Market Operational 2000
Liberty Electric......... PA 530 530 Contract Natural Gas Competitive Market Construction 2002
Athens................... NY 1,080 1,080 Owned Natural Gas Competitive Market Development 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................ 4,838 4,254
------ ------
Midwest Region
Georgetown............... IN 240 160 Contract Natural Gas Competitive Market Operational 2000
Ohio Peakers............. OH 144 144 Owned Natural Gas Competitive Market Construction 2001
Covert................... MI 1,170 1,170 Owned Natural Gas Competitive Market Development 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 Operational 1995
Agreement
Cedar Bay................ FL 269 135 Owned Coal Power Purchase Operational 1994
Agreement
Attala................... MS 500 500 Owned Natural Gas Competitive Market Construction 2001
SRW(4)................... TX 420 250 Contract Natural Gas Competitive Market Construction 2001
Southaven................ MS 810 810 Contract Natural Gas Competitive Market Development 2003
Unannounced toll......... 810 810 Contract Natural Gas Competitive Market Development 2003
------ ------
Subtotal................ 3,169 2,631
------ ------
Western Region
Hermiston................ OR 474 237 Owned Natural Gas Power Purchase Operational 1996
Agreement
Colstrip................. MT 40 5 Owned Waste Coal Power Purchase Operational 1990
Agreement
Mountain View............ CA 66 66 Owned(5) 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 Development 2002
Harquahala............... AZ 1,080 1,080 Leased Natural Gas Competitive Market Development 2003
Otay Mesa................ CA 500 250 Contract(6) 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................ 5,186 4,664
------ ------
Total................... 24,240 22,179
====== ======
46
- --------
(1) 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.
(2) 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.
(3) Millennium achieved commercial operation in April 2001.
(4) One of our subsidiaries entered into a contract with SRW Cogeneration
Limited Partnership dated as of July 30, 1999 pursuant to which we would
control 250 MW of a 420 MW cogeneration facility the limited partnership
is building and is to operate. The limited partnership has provided us
with notice of its purported termination of the contract as the result of
the downgrades of the debt of PG&E Corporation, the guarantor under the
tolling agreement. We are contesting the termination because we do not
believe the conditions for such a termination have been met.
(5) We have executed a contract to purchase the Mountain View facility when
construction is completed. The purchase has not yet closed.
(6) We have entered into arrangements to sell the Otay Mesa facility and
retain 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.
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.
47
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 sells approximately 97% of its electrical capacity and output to
Boston Edison Company, Western Massachusetts Electric Co., 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,
approximately 5.54% during winter and 2% during summer, to Consolidated Edison
Company of New York, Inc. 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. Alstom
is implementing a recovery plan with a target commercial operations date in the
fourth quarter of 2001. 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 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 minimum 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.
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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 Development
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.
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.
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 Development
Covert. Covert is an approximately 1,170 MW natural gas-fired combined-cycle
project currently under development in Covert, Michigan. This project will
consist of three Mitsubishi 501G combustion turbine generators and associated
systems and facilities. This project, along with Badger and Goose Lake, is
expected to be 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.
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. 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. 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
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 15
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.
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.
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Generating Facilities Under Construction
Attala Power Project. The Attala Power Project is a 500 MW natural gas-fired
combined-cycle power plant that is currently under construction in Attala
County, Mississippi. We acquired Attala from Duke Energy North America in
September 2000. Attala will consist of two General Electric 7FA combustion
turbine generators. This facility is anticipated to sell all of its electric
output in the competitive market. Attala will be 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.
Attala is expected to commence commercial operations in the second half of
2001.
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 the second quarter of 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
minimum guaranteed performance levels, we may be able to collect liquidated
damages from Alstom.
Generating Facilities In Development
Harquahala. Harquahala is an approximately 1,080 MW natural gas-fired
combined-cycle generating project near Phoenix, Arizona. We have recently
commenced initial construction-related activities at the project site. 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.
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. We have entered into
agreements to sell this project and retain control of 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. This
sale is expected to close in the second quarter of 2001, subject to regulatory
approval.
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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 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 4.4% 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%
Iroquois Gas
Transmission System.... NY, CT 1991 900 95% 375 4.4%
North Baja.............. AZ, CA 2002 500 N/A 77 100%
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 over 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
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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.
. 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 due to a firm transportation customer not
fully utilizing its committed capacity. 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, 200 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
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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 the high amount of interest shown by potential customers, we are
preparing to commence a solicitation or "open season" for additional customers.
Depending on the results of the open season, the second phase, expected to be
300 million to 500 million cubic feet per day, could be completed as early as
the end of 2003.
Iroquois Pipeline
We own a 4.4% 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. 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 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 April 30, 2001, we owned or leased 5,590 MW of electric generating
capacity and are constructing and developing an additional 12,346 MW of
electric generating capacity that 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.
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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.
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 Mountain, 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,
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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.
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.
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 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
57
these projects. Although we expect that FERC will issue us the new license for
the Fifteen Mile Falls project, we cannot guarantee that it will do so by the
July 31, 2001 expiration date, but 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 pipe-
lines and related facilities used in the transportation, storage and sale (for
resale) of natural gas in interstate commerce and the rates, terms and condi-
tions for the transportation and sale (for resale) of natural gas in interstate
commerce. Both the GTN and Iroquois pipelines are considered "natural gas com-
panies" under the Natural Gas Act, and we hold the required certificates of
public convenience and necessity from FERC to operate these pipelines and re-
lated facilities and properties. The North Baja pipeline has filed an applica-
tion with FERC for a certificate of public convenience and necessity to con-
struct 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 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-Canadian 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
58
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).
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.
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
59
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.
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
made public on April 23, 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
60
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 SO\\2\\,
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, SO\\2\\, mercury and CO\\2\\. 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 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 made public by the State Initiative for 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
61
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 SO\\2\\ emissions. Implementation of the acid rain provisions is
achieved through a total cap on SO\\2\\ emissions from affected units and an
allocation of marketable SO\\2\\ allowances to each affected unit. Operators of
electric generating units that emit SO\\2\\ in excess of their allocations can
buy additional allowances from other affected sources. We currently project the
number of SO\\2\\ allowances allocated to our New England units will be greater
than projected SO\\2\\ emissions through 2010. Whether we will have an excess
or deficit of SO\\2\\ 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. In addition to the Kyoto Protocol, other initiatives may
address CO\\2\\ emissions in the future. For example, several bills have been
introduced in Congress that address, among other things, CO\\2\\ 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 CO\\2\\ 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 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 SO\\2\\ 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
62
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 pursuant to
Section 114 of the Clean Air Act from EPA 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 made public
on April 23, 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 April 23, 2001, the Massachusetts
Department of Environmental Protection made public restrictions, to be formally
issued on or about May 11, 2001, imposing new restrictions on emissions of NOx
and SO\\2\\, mercury and carbon dioxide from existing coal-fired power plants.
These restrictions will impose more stringent annual and monthly limits on NOx
and SO\\2\\ than currently exist and 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. Mercury emissions are capped as
a first step and will require reduction pursuant to standards to be developed
that must be met by October 2006. CO\\2\\ emissions are regulated for the first
time and will require reductions over recent historical levels. We believe that
compliance with the CO\\2\\ caps can be achieved through a number of
strategies, including sequestrations and offsite reductions. Various testing
and recordkeeping requirements are also imposed.
By 2002, we plan to have in operation in New England approximately 5,100 MW
of generating capacity. The new Massachusetts regulations affect primarily our
Brayton Point and Salem Harbor generating facilities, representing
approximately 2,300 MW. Through 2008, 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, it
may be necessary for us to implement field 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,
63
Brayton Point and Salem Harbor stations) are operating in substantial
compliance with National Pollutant Discharge Elimination System, or NPDES,
permits that have expired. We anticipate that all three will be able to
continue to do so 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, has expressed
concern that the metal vanadium is not addressed at Brayton Point 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.
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
64
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. 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 March 31, 2001, we employed approximately 2,191 people. Of these
employees, approximately 523 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 relations with our employees
to be good.
Facilities/Properties
Our corporate offices currently occupy approximately 250,000 square feet of
leased office space in several buildings in Bethesda and Rockville, Maryland.
65
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
document. 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. We are currently in negotiations with a developer to build
and lease a special purpose headquarters and energy trading facility of
approximately 450,000 square feet for us in Rockville, Maryland. This new
facility is expected to commence construction in late 2001 and would be
available for occupancy as early as the end of 2002. We would enter into a
long-term operating lease for this property.
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 based on recalculation of past energy
payments using heat rates lower than those reported by Logan in prior invoices
in the amount of $4 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.
Energy Trading Litigation
A power marketer filed suit in October 1998 against PG&E Energy Trading-
Power, L.P., or 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 is unable to predict whether the
outcome of this litigation will have a material adverse effect on our financial
condition or results of operations.
66
A creditor's involuntary bankruptcy petition was filed 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 is unable to predict whether the outcome of this litigation
will have a material adverse effect on our financial condition or results of
operations.
67
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, respectively. 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 generally are required to pay
to PG&E Corporation the amount of income taxes that we would record if we filed
our own consolidated combined or unitary return separate from PG&E Corporation.
In addition, in the recent past Pacific Gas and Electric Company has been
GTN's largest customer and, during 1998, 1999 and 2000, accounted for $49
million, $47 million and $46 million, respectively, of the revenues generated
by our GTN pipeline. In addition, our energy trading operation 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, our energy trading operations had energy commodity sales of approximately
$0.8 million, $30 million and $136 million to Pacific Gas and Electric Company
and energy commodity purchases of $0.7 million, $7 million and $12 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, 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 December 31, 2000, we had a net outstanding loan balance payable
to PG&E Corporation of $234 million. 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, 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.
68
As of April 30, 2001, except for $153 million of guarantees under various
energy trading contracts and $314 million in equity infusion agreements, we
have 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 is 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. We are in discussions with our
energy trading counterparties and lenders, and expect to replace the balance of
the PG&E Corporation equity infusion agreements and guarantees before July 2,
2001. Our inability to replace these agreements and guarantees in accordance
with PG&E Corporation's term loans is a default under those loans which could
result 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 motions to intervene out of time, 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 a tolling order granting rehearing of
the February 21 order for the limited purpose of affording additional time for
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 to
any entity;
. the institution or consent to institution of a bankruptcy, insolvency,
or similar proceeding or action; or
. the declaration or payment of dividends or the making of intercompany
loans.
In addition, if a dividend is to be paid, the payor must have an investment
grade credit rating or meet a 2.25 to 1.00 consolidated interest coverage ratio
and a 0.70 to 1.00 consolidated leverage ratio, as applicable.
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.
69
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 document) or
the activities comply with certain other negotiated exceptions. The credit
agreement also restricts 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, 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), 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 also 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%
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.
70
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, including Pacific Gas and Electric Company, 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
. the holding companies' action to "ringfence" their unregulated
subsidiaries.
The CPUC will also 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 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.
71
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.............................. F-5
Consolidated Balance Sheets
As of December 31, 1999 and 2000.......................................... 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.............................. 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 statment 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.
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
Years Ended December 31, 1998, 1999 and 2000
(In Millions)
1998 1999 2000
------- ------- -------
OPERATING REVENUES:
Generation, transportation, and trading............ $10,533 $11,957 $16,930
Equity in earnings of affiliates................... 117 63 65
------- ------- -------
Total operating revenues........................ 10,650 12,020 16,995
------- ------- -------
OPERATING EXPENSES:
Cost of commodity sales and fuel................... 9,874 10,982 15,667
Operations, maintenance, and management............ 395 601 716
Administrative and general......................... 45 49 68
Depreciation and amortization...................... 167 214 143
Impairments and write-offs......................... -- 1,275 --
Other operating expenses........................... 7 5 10
------- ------- -------
Total operating expenses........................ 10,488 13,126 16,604
------- ------- -------
OPERATING INCOME (LOSS)............................. 162 (1,106) 391
OTHER INCOME (EXPENSES):
Interest income.................................... 45 75 80
Interest expense................................... (156) (162) (155)
Other income (expense)--net........................ (7) 52 6
------- ------- -------
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
INCOME TAXES....................................... 44 (1,141) 322
Income tax expense (benefit)....................... 41 (351) 130
------- ------- -------
Income (loss) from continuing operations........ 3 (790) 192
------- ------- -------
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........ -- (58) (40)
------- ------- -------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE..................... (54) (895) 152
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE-- Net of applicable income taxes of $8
million............................................ -- 12 --
------- ------- -------
NET INCOME (LOSS)................................... $ (54) $ (883) $ 152
======= ======= =======
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
December 31, 1999 and 2000
(In Millions)
1999 2000
------ -------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................... $ 228 $ 738
Restricted cash.............................................. 81 53
Accounts receivable, trade (net of allowance for
uncollectibles of $19 million and $19 million,
respectively)............................................... 1,047 2,470
Other receivables............................................ -- 159
Note receivable from Parent.................................. -- 75
Inventory.................................................... 133 112
Price risk management assets--current........................ 389 2,039
Assets related to discontinued operations--current........... 114 --
Prepaid expenses, deposits, and other........................ 133 474
------ -------
Total current assets...................................... 2,125 6,120
------ -------
PROPERTY, PLANT, AND EQUIPMENT:
Property, plant, and equipment in service.................... 4,607 3,747
Accumulated depreciation..................................... (770) (757)
------ -------
3,837 2,990
Construction work in progress................................ 217 650
------ -------
Total property, plant, and equipment--net................. 4,054 3,640
------ -------
OTHER NONCURRENT ASSETS:
Long-term receivables........................................ 611 536
Investments in unconsolidated affiliates..................... 530 417
Goodwill, net of accumulated amortization of $14 million and
$25 million, respectively................................... 105 100
Price risk management assets--noncurrent..................... 319 2,026
Assets related to discontinued operations--noncurrent........ 83 --
Other........................................................ 239 267
------ -------
Total noncurrent assets................................... 1,887 3,346
------ -------
TOTAL ASSETS.................................................. $8,066 $13,106
====== =======
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
December 31, 1999 and 2000
(In Millions)
1999 2000
------ -------
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term borrowings........................................ $ 524 $ 519
Long-term debt--current portion.............................. 93 17
Obligations due related parties and affiliates............... 33 309
Accounts payable:
Trade....................................................... 853 2,170
Related parties............................................. 73 156
Accrued expenses............................................. 152 281
Price risk management liabilities--current................... 323 1,999
Out-of-market contractual obligations--current portion....... 163 141
Liabilities related to discontinued operations--current...... 61 --
Other........................................................ 121 241
------ -------
Total current liabilities................................. 2,396 5,833
------ -------
NONCURRENT LIABILITIES:
Long-term debt............................................... 1,805 1,390
Deferred income taxes........................................ 650 792
Price risk management liabilities--noncurrent................ 207 1,867
Out-of-market contractual obligations--noncurrent............ 941 800
Liabilities related to discontinued operations--noncurrent... 10 --
Long-term advances from Parent............................... 44 --
Other noncurrent liabilities and deferred credit............. 131 45
------ -------
Total noncurrent liabilities.............................. 3,788 4,894
------ -------
MINORITY INTEREST............................................. 21 18
COMMITMENTS AND CONTINGENCIES................................. -- --
PREFERRED STOCK OF SUBSIDIARY................................. 57 57
COMMON STOCKHOLDER'S EQUITY:
Capital stock, $1.00 par value--1,000 shares issued and
outstanding................................................. -- --
Paid-in capital.............................................. 2,737 3,086
Retained accumulated deficit................................. (933) (781)
Accumulated other comprehensive income....................... -- (1)
------ -------
Total common stockholder's equity......................... 1,804 2,304
------ -------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................... $8,066 $13,106
====== =======
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
Years Ended December 31, 1998, 1999 and 2000
(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
Years Ended December 31, 1998, 1999 and 2000
(In Millions)
1998 1999 2000
------- ------ -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................... $ (54) $ (883) $ 152
Adjustments to reconcile net income (loss):
Depreciation and amortization....................... 167 214 143
Deferred income taxes............................... 150 (227) 161
Amortization of out-of-market contractual
obligation......................................... (65) (181) (163)
Other deferred credits and noncurrent liabilities... 54 (77) (89)
(Gain) loss on impairment or sale of assets......... 11 1,256 (16)
Loss from discontinued operations................... 57 105 40
Equity in earnings of affiliates.................... (117) (63) (65)
Distribution from affiliates........................ 69 66 104
Cumulative effect of change in accounting
principle.......................................... -- (12) --
Net effect of changes in working capital assets and
liabilities:
Restricted cash..................................... 33 (14) 28
Accounts receivable--trade.......................... 321 (387) (1,498)
Inventories, prepaids and deposits.................. (228) (56) (339)
Price risk management assets and liabilities--net... (21) (121) (21)
Accounts payable and accrued liabilities............ (624) 276 1,446
Accounts payable--related parties................... 295 (2) 83
Other--net.......................................... 16 180 197
------- ------ -------
Net cash provided by operating activities.......... 64 74 163
------- ------ -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures................................ (221) (150) (312)
Acquisition of generating assets.................... (1,746) -- (311)
Proceeds from sale--leaseback....................... 479 -- --
Proceeds from sale of assets (equity investments)... 228 90 442
Long-term receivable................................ 20 66 75
Other--net.......................................... (45) (69) (38)
------- ------ -------
Net cash used in investing activities.............. (1,285) (63) (144)
------- ------ -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings (repayments) under credit
facilities......................................... 193 231 (5)
Long-term debt issued............................... 378 129 --
Long-term debt matured, redeemed, or repurchased.... -- (269) (85)
Advances (to) from Parent........................... 44 (6) 79
Capital contributions............................... 624 75 608
Distributions....................................... (151) (111) (106)
------- ------ -------
Net cash provided by financing activities.......... 1,088 49 491
------- ------ -------
NET CHANGE IN CASH AND CASH EQUIVALENTS.............. (133) 60 510
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR......... 301 168 228
------- ------ -------
CASH AND CASH EQUIVALENTS, END OF YEAR............... $ 168 $ 228 $ 738
======= ====== =======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for:
Interest--net of amount capitalized................. $ 143 $ 153 $ 148
Income taxes--net of refunds........................ (90) (162) (12)
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND
FINANCING:
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
Long-term debt assumed from purchase of Attala
Generating Company................................. -- -- (159)
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
Years Ended December 31, 1998, 1999 and 2000
1. ORGANIZATION AND BASIS OF PRESENTATION
PG&E National Energy Group, Inc., is a wholly owned subsidiary of PG&E
Corporation ("Parent"). PG&E National Energy Group, Inc., and its subsidiaries
(collectively, "NEG", "National Energy Group", 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"), PG&E Energy Trading Holdings Corporation and its subsidiaries
(collectively, "Energy Trading" or "ET"), PG&E Gas Transmission, Northwest
Corporation and 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 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 Parent. Shortly thereafter, Parent contributed
various subsidiaries to the NEG. The consolidated financial statements of NEG
for the years ended December 31, 1998, 1999 and 2000, 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 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 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 factors. The results of
operations in these consolidated financial statements also include general
corporate expenses allocated by 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 operated as a separate entity.
2. RELATIONSHIP WITH THE PARENT AND THE CALIFORNIA ENERGY CRISIS
Through the periods covered by these financial statements, 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 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, surety bonds and letters of credit. 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.
F-10
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 equtiy 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 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, GTN and ET to receive or retain
their own credit rating, based upon their creditworthiness. The ringfencing
involved the creation of new special purpose entities ("SPEs") as intermediate
owners between the Parent and its NEG subsidiaries. These new 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. Ringfencing is intended to
reduce the likelihood that the assets of the ringfenced entities would be
substantially consolidated in a bankruptcy proceeding involving such companies'
ultimate parent, and to thereby preserve the value of the "protected" entities
as a whole. 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 dividends
unless the respective boards of directors have unanimously approved such action
and the company meets specified financial requirements. After the ring-fencing
structure was implemented, two independent rating agencies, Standard & Poor's
and Moody's reaffirmed investment grade ratings for GTN and Gen 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
F-11
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
combination of guarantees provided by Company subsidiaries and letters of
credit obtained independently by the Company. The Company is also in the
process of negotiating substitute equity commitments with certain third parties
to construction financing agreements. The substitute equity commitments offered
by the Company are intended to replace the $1 billion of Parent guarantees and
equity commitments under the construction financing agreements. As long as the
Parent equity commitments have not been substituted with alternative equity
commitments, construction under the related projects could be suspended or
delayed.
As of December 31, 2000, Attala Power Corporation ("APC"), an indirect
wholly-owned subsidiary of the Company, has a non-recourse demand note payable
to the Parent (see Note 8) of $309 million and GTN has a note receivable from
the Parent of $75 million. 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 notes, 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 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.
F-12
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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. The Company accounts for hedging activities under the deferral method,
whereby the Company defers unrealized gains and losses on hedging transactions.
When the underlying item settles, the Company recognizes the gain or loss from
the hedge instrument in operating income. In instances where the anticipated
correlation of price movements does not occur, hedge accounting is terminated
and future changes in the value of the derivative are recognized as gains or
losses. If the hedged item is sold, the value of the associated derivative is
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 will adopt Statement of Financial Accounting Standards ("SFAS")
No. 133, Accounting for Derivative Instruments and Hedging Activities, as
amended by SFAS Nos. 137 and 138, on January 1, 2001. This standard requires
the Company to recognize all derivatives, as defined in the Statement, on the
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 until the hedged items are recognized
in earnings. The Company estimates that the transition adjustment to implement
this new standard will be 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, will be recognized as of January 1, 2001, as a cumulative effect of a
change in accounting principle. 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 SFAS No. 133 under the normal purchases and sales
exception, and thus will not be reflected on the balance sheet at fair value.
The Derivatives Implementation Group of the FASB has reached a conclusion that
if adopted would change the definition of normal purchases and sales. As such,
certain derivative commodity contracts may no longer be exempt from the
requirements of SFAS No. 133. When the final decision regarding this issue is
complete, the Company will evaluate the impact of the implementation guidance
on a prospective basis.
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-13
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-14
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 --------------
Lives 1999 2000
-------------- ------ ------
Electric generating facilities................ 20 to 50 years $1,789 $1,955
Gas transmission.............................. 15 to 40 years 2,383 1,477
Other......................................... 2 to 20 years 298 190
Land.......................................... 137 125
------ ------
4,607 3,747
Less: Accumulated depreciation................ (770) (757)
------ ------
Property, plant, and equipment--net........... 3,837 2,990
Construction in progress...................... 217 650
------ ------
$4,054 $3,640
====== ======
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-15
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,
Amortization -----------
Period 1999 2000
------------ ------ ----
PPAs............................................... 1-20 years $ 660 $599
Gas Agreements..................................... 8-13 years 205 188
Standard Offer Agreements.......................... 6-7 years 239 154
------ ----
1,104 941
Less: Current portion.............................. 163 141
------ ----
Long-term portion.................................. $ 941 $800
====== ====
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 revenues, including
the reservation and the volumetric charge components, are recorded as services
are
F-16
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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.
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.
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 Issues 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 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.
F-17
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, $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 also 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.
F-18
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 is subject to adjustment during a 120-day working capital true-up
period. 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
====== ======= ======
On September 28, 2000, the Company, through its indirect subsidiary APC,
purchased for $311 million the Attala Generating Company, LLC, which owns a
gas-fired power plant 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, is expected to begin commercial service in July 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.
F-19
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
Derivative Purchase Sale Max Term
Nontrading Activities Type (Long) (Short) (Years)
--------------------- ---------- -------- ------- --------
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
==== ==== =====
F-20
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.
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
F-21
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
to the terms of their contractual obligation. 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.
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.
F-22
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Operating entities which the Company does not control are as follows (in
millions):
NEG's Share
of Entity NEG's
As of 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.
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
====== ======
F-23
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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.
F-24
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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 --
Senior Notes
GTN (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)
Bonds payable (non-
Gen recourse)............... 2010 10% -- 159
Term Loans (non-
recourse)............... 2009-2011 Various 116 107
Outstanding Credit
Facilities (Note 8)..... 2003 Various 550 575
Mortgage loan payable... 2010 30-day commercial
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, 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).
F-25
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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.
F-26
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 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.
F-27
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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.
F-28
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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-29
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 at different tax rates... 10 (5) (3)
Amortization of goodwill............................ 4 7 1
Stock sale valuation allowance...................... -- 79 --
Stock sale differences.............................. -- (17) (10)
Other--net.......................................... 6 (23) 24
----- ------- ----
Effective tax........................................ $ 41 $ (351) $130
===== ======= ====
F-30
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
==== ====
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-31
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):
Power Gas Supply and
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 June 30, 2002 in
New Hampshire, 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 2001
and 2002, the lease terms of 5 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 postconstruction periods. As discussed in Note 2,
the Company is attempting to replace the Parent equity support commitments with
substitute commitments of NEG.
F-32
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
------
Total............................................................... $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 similar to the other projects under construction
described above. As discussed in Note 2, the Company is attempting to replace
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. As discussed in Note 2, the Company
is attempting to replace the Parent equity support commitments with substitute
commitments of NEG.
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 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
F-33
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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 is expected to commence in June 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.
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. Except as described below, 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 financial condition or
results of operations.
F-34
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 based on recalculation of
past energy payments using heat rates lower than those reported by Logan in
prior invoices in the amount of $4 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.
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 is not able to assess the likelihood of an unfavorable outcome of
this matter or estimate the amount or range of potential loss, if any.
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 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 is not able to assess the likelihood of an unfavorable
outcome of this matter or estimate the amount or range of potential loss, if
any.
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.
F-35
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 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 and thermal emissions by 2007 to 2010. Management believes that
the Company would meet these requirements through installation of controls at
the Brayton Point and Salem Harbor plants and estimates that capital
expenditures on these environmental projects approximate $271 million over the
next six years. The Massachusetts Department of Environmental Protection
("DEP") may require earlier compliance, which the Company believes may not be
feasible and would require the use of credit allowances it currently owns or
the purchase of additional credit allowances. 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 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. It is estimated that USGenNE's cost to comply with the new
permit conditions could be as much as $55 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
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.
F-36
PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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
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PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
The Utility is current on all billings due to GTN through March 16, 2001, and
has indicated its intention to remain current. GTN's accounts receivable from
the Utility at December 31, 2000 of $3.7 million was collected in January 2001.
* * * * * *
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