EXHIBIT 99
ITEM 1. BUSINESS
OUR BUSINESS
RERC CORP. RESTRUCTURING
Following the Restructuring, CenterPoint Energy will be a utility holding
company under the 1935 Act and as such will be required to register under the
1935 Act unless it qualifies for an exemption. In order to enable CenterPoint
Energy to comply with the requirements in the exemption in Section 3(a)(1) of
the 1935 Act, we plan to divide the gas distribution businesses conducted by
RERC Corp.'s three unincorporated divisions, Reliant Energy Entex (Entex),
Reliant Energy Arkla (Arkla) and Reliant Energy Minnegasco (Minnegasco), among
three separate business entities. For more information regarding our application
under the 1935 Act and regulation under the 1935 Act, please read
"Regulation -- Public Utility Holding Company Act of 1935" in Item 1 of this
Form 10-K. The entity that will hold the Entex assets will also hold RERC
Corp.'s natural gas pipelines and gathering businesses. For more information
regarding RERC Corp.'s divisions and their operations, please read "Natural Gas
Distribution" and "Pipelines and Gathering" in Item 1 of this Form 10-K. In
addition to regulatory approvals we have obtained, this restructuring will
require approval of the public service commissions of Louisiana, Oklahoma and
Arkansas.
ITEM 3. LEGAL PROCEEDINGS
For a description of certain legal and regulatory proceedings affecting us,
see Notes 4, 14(f), 14(g) and 21 to our consolidated financial statements, which
notes are incorporated herein by reference.
RESTATEMENT OF SECOND AND THIRD QUARTER 2001 RESULTS OF OPERATIONS
On February 5, 2002, Reliant Energy announced that it was restating its
earnings for the second and third quarters of 2001. As more fully described in
Reliant Energy's March 15, 2002 Current Report on Form 8-K, the restatement
related to a correction in accounting treatment for a series of four structured
transactions that were inappropriately accounted for by Reliant Resources as
cash flow hedges for the period of May 2001 through September 2001, rather than
as derivatives with changes in fair value recognized through the income
statement. Each structured transaction involved a series of forward contracts to
buy and sell an energy commodity in 2001 and to buy and sell an energy commodity
in 2002 or 2003.
At the time of the public announcement of Reliant Energy's intention to
restate its reporting of the structured transactions, the Audit Committees of
each of the boards of directors of Reliant Energy and Reliant Resources
instructed Reliant Resources to conduct an internal audit review to determine
whether there were any other transactions included in the asset books as cash
flow hedges that failed to meet the cash flow hedge requirements under Statement
of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133). This targeted internal audit
review found no other similar transactions.
The Audit Committees also directed an internal investigation by outside
legal counsel of the facts and circumstances leading to the restatement, which
investigation has been completed. In connection with the restatement and related
investigations, the Audit Committees have met eight times to hear and assess
reports from the investigative counsel regarding its investigation and contacts
with the staff of the SEC. To address the issues identified in the investigation
process, the Audit Committees and management have begun analyzing and
implementing remedial actions, including, among other things, changes in
organizational structure and enhancement of internal controls and procedures.
On April 5, 2002, Reliant Resources was advised that the Staff of the
Division of Enforcement of the SEC is conducting an informal inquiry into the
facts and circumstances surrounding the restatement. Reliant Resources is
cooperating with this inquiry. Before releasing its 2001 earnings, Reliant
Energy received concurrence from the SEC's accounting staff on the accounting
treatment of the restatement, which increased its earnings for the two quarters
by a total of $107 million. At this time, we cannot predict the outcome of the
SEC's inquiry. In addition, we cannot predict what effect the inquiry may have
on our pending application to the SEC under the 1935 Act, which is required for
our Restructuring. For more information about our Restructuring, please read
"Our Business -- Status of Business Separation" and "-- Business Separation" in
Item 1 of this Form 10-K.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS
Our past earnings are not necessarily indicative of our future earnings and
results of operations. The magnitude of our future earnings and results of our
operations will depend on numerous factors including:
- state, federal and international legislative and regulatory developments,
including deregulation, re-regulation and restructuring of the electric
utility industry, changes in or application of environmental and other
laws and regulations to which we are subject and changes in or
application of laws or regulations applicable to other aspects of our
business, such as commodities trading and hedging activities;
- the timing of the implementation of our Business Separation Plan;
- the effects of competition, including the extent and timing of the entry
of additional competitors in our markets;
- liquidity concerns in our markets;
- industrial, commercial and residential growth in our service territories;
- the degree to which Reliant Resources successfully integrates the
operations and assets of Orion Power into the Wholesale Energy business
segment;
- the determination of the amount of our Texas generation business'
stranded costs and the recovery of these costs;
- the availability of adequate supplies of fuel, water, and associated
transportation necessary to operate our generation facilities;
- our pursuit of potential business strategies, including acquisitions or
dispositions of assets or the development of additional power generation
facilities;
- state, federal and other rate regulations in the United States and in
foreign countries in which we operate or into which we might expand our
operations;
- the timing and extent of changes in interest rates and commodity prices,
particularly natural gas prices;
- weather variations and other natural phenomena, which can affect the
demand for power from, or our ability to produce power at our generating
facilities;
- our ability to cost-effectively finance and refinance;
- the degree to which we successfully integrate the operations and assets
of Orion Power into our Wholesale Energy segment;
- the successful and timely completion of our construction programs, as
well as the successful start-up of completed projects;
- financial market conditions, our access to and cost of capital and the
results of our financing and refinancing efforts, including availability
of funds in the debt/capital markets for merchant generation companies;
- the credit worthiness or bankruptcy or other financial distress of our
trading, marketing and risk management services counterparties;
- actions by rating agencies with respect to us or our competitors;
- acts of terrorism or war;
- the availability and price of insurance;
- the reliability of the systems, procedures and other infrastructure
necessary to operate our retail electric business, including the systems
owned and operated by ERCOT;
- political, legal, regulatory and economic conditions and developments in
the United States and in foreign countries in which we operate or into
which we might expand our operations, including the effects of
fluctuations in foreign currency exchange rates;
- the resolution of the refusal by California market participants to pay
our receivables balances due to the recent energy crisis in the West
region; and
- the successful operation of deregulating power markets.
In order to adapt to the increasingly competitive environment in our
industry, we continue to evaluate a wide array of potential business strategies,
including business combinations or acquisitions involving other utility or
non-utility businesses or properties, dispositions of currently owned
businesses, as well as developing new generation projects, products, services
and customer strategies.
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FACTORS ASSOCIATED WITH THE BUSINESS SEPARATION, RESTRUCTURING AND DISTRIBUTION
As previously discussed, in anticipation of electric deregulation in Texas,
and pursuant to the Texas Electric Restructuring Law, we submitted a business
separation plan in January 2000 to the Texas Utility Commission. Pursuant to the
Business Separation Plan, we are in the process of separating our regulated and
our unregulated businesses into two separate publicly traded companies.
After the Restructuring, we plan, subject to further corporate approvals,
market and other conditions, to complete the separation of our regulated and
unregulated businesses through the Distribution. Our goal is to complete the
Restructuring and subsequent Distribution as quickly as possible after all the
necessary conditions are fulfilled, including receipt of an order from the SEC
granting the required approvals under the Public Utility Holding Company Act of
1935 (1935 Act) and an extension from the IRS for a private letter ruling we
have obtained regarding the tax-free treatment of the Distribution. We currently
expect to complete the Restructuring and Distribution in the summer of 2002. See
"Our Business -- Business Separation" in Item 1 of this Form 10-K.
Regulatory Uncertainty. The Restructuring as currently planned cannot be
completed unless and until the SEC issues an order approving the acquisition by
CenterPoint Energy of Reliant Energy and its subsidiary companies and either
granting CenterPoint Energy an exemption from regulation as a registered public
utility holding company under the 1935 Act or the necessary authority to operate
as a registered holding company. While we believe such an order will be
received, and that both the Restructuring and Distribution will be completed
during the summer of 2002, there can be no assurances that such will be the
case. The Restructuring has been designed to enable us to meet all of the
requirements of the Texas Electric Restructuring Law. We have not formulated an
alternative restructuring plan that could be implemented if the SEC fails or
refuses to grant an exemption for CenterPoint Energy or the authority for
CenterPoint Energy to become a registered holding company on terms consistent
with our business plan. For information about an informal inquiry by the staff
of the Division of Enforcement of the SEC in connection with an earnings
restatement by Reliant Energy that might impact the approval process, please
read "Restatement of Second and Third Quarter 2001 Results of Operations" in
Item 3 of this Form 10-K.
The tax ruling that we received from the IRS expires at the end of April
2002. We are currently seeking an extension of this ruling from the IRS. There
can be no assurance that we will receive the extension quickly or at all. In
this event, the Restructuring and Distribution are not likely to be completed
within our expected time frame, or, perhaps, at all. In addition, our tax ruling
contemplates that the Restructuring will occur prior to the Distribution. If,
due to delay or uncertainty regarding receipt of an order under the 1935 Act, we
decide to make the Distribution before completing the Restructuring, we would
have to seek a new ruling from the IRS that the Distribution would be tax free
to us and to our shareholders. This process could take six months or longer.
A significant delay in completing the Restructuring and the Distribution
may impact planned financings by each of Reliant Energy and Reliant Resources
and make it more difficult and more expensive for us to obtain bank financing.
We cannot predict how any such delay might impact our credit ratings or those of
Reliant Resources.
Adverse Tax Consequences. If we take actions which cause the Distribution
to fail to qualify as a tax-free transaction, we will incur taxable gain equal
to the positive difference between the value of the Reliant Resources shares
distributed and our tax basis in those shares. Current tax law provides that,
depending on the facts and circumstances, the Distribution may be taxable if
either CenterPoint Energy or Reliant Resources undergo a 50% or greater change
in stock ownership within two years after the Distribution. These costs may be
so great that they delay or prevent a strategic acquisition or change in control
of our company. If Reliant Resources takes actions which cause the Distribution
to fail to qualify as a tax-free transaction, for example, through a change in
control of Reliant Resources, we will be responsible for the tax due on the gain
but may seek indemnity from Reliant Resources for such payments.
Credit. To the extent that we continue to need access to current amounts
of committed credit prior to the Distribution, we expect to extend or replace
the credit facilities on a timely basis. The terms of any new
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credit facilities are expected to be adversely affected by our leverage, the
amount of bank capacity utilized, any delay in the date of Restructuring and
Distribution and conditions in the bank market. These same factors are expected
to make the syndication of new credit facilities more difficult in the future.
Proceeds from any issuance of debt in the capital markets are expected to be
used to retire a portion of our short-term debt and reduce our need for
committed revolving credit facilities.
FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC OPERATIONS
Deregulation. In June 1999, the Texas legislature adopted the Texas
Electric Restructuring Law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail competition.
Retail pilot projects for up to 5% of each utility's load in all customer
classes began in August 2001 and retail electric competition for all other
customers began on January 1, 2002. We have made significant changes in the
electric utility operations previously conducted through Reliant Energy HL&P.
For additional information regarding these changes, please read "Our
Business -- Deregulation," "-- Electric Operations," "-- Regulation -- State and
Local Regulations -- Texas -- Electric Operations -- The Texas Electric
Restructuring Law" and "-- Our Business Going Forward" in Item 1 of this Form
10-K and Note 4 to our consolidated financial statements.
Transmission and Distribution. Under the Texas Electric Restructuring Law,
our T&D Utility will remain subject to traditional rate regulation by the Texas
Utility Commission, and we will collect from retail electric providers the rates
approved in the T&D Utility's rate case (Wires Case) to cover the cost of
providing transmission and distribution service and any other expenses. Our
ability to earn the rate of return built into the T&D Utility's rates may be
affected, positively or negatively, to the extent that the T&D Utility's actual
expenses or revenues differ from the estimates used to set the T&D Utility's
rates.
Generation. As described under "Electric Operations -- Generation," since
January 1, 2002, we have been obligated to sell substantially all of the
generating capacity and related ancillary services of our Texas generation
business through auctions. As a result, we are not guaranteed any rate of return
on our investment in these generation facilities through mandated rates, and our
revenues and results of operations are likely to depend, in large part, upon
prevailing market prices for electricity in the Texas market and the related
results of our capacity auctions. These market prices may fluctuate
substantially over relatively short periods of time. In addition, ERCOT, the
independent system operator for the Texas markets, may impose price limitations,
bidding rules and other mechanisms that may impact wholesale power prices in the
Texas market and the outcome of our capacity auctions. Our historical financial
results represent the results of our Texas generation business as part of an
integrated utility in a regulated market and may not be representative of its
results as a stand-alone wholesale electric power generation company in an
unregulated market. Therefore, the historical financial information included in
this report does not necessarily reflect what our financial position, results of
operations and cash flows would have been had our generation facilities been
operated in an unregulated market.
Under the terms of the auctions pursuant to which we are obligated to sell
our capacity, we are obligated to provide specified amounts of capacity to
successful bidders. The products we sell in the auctions are only entitlements
to capacity dispatched from our units and do not convey the right to have power
dispatched from a particular unit. This flexibility exposes us to the risk that,
depending on the availability of our units, we could be required to supply
energy from a higher cost unit to meet an obligation for lower cost generation
or to obtain the energy on the open market. Obtaining such replacement
generation could involve significant additional costs. We manage this risk by
maintaining appropriate reserves within our generation asset base but these
reserves may not cover an entire exposure in the event of a significant outage
at one of our facilities. For information about operating risks associated with
our Texas generation business, please read "Factors Affecting the Results of Our
Wholesale Energy Operations -- Operating Risks" below.
Also, market volatility in the price of fuel for our generation operations,
as well as in the price of purchased power, could have an effect on our cost to
generate or acquire power. For additional information regarding commodity prices
and supplies, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Price Volatility."
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Pursuant to the Texas Electric Restructuring Law, we will be entitled to
recover our stranded costs (i.e., the excess of regulatory net book value of
generation assets, as defined by the Texas Electric Restructuring Law, over the
market value of those assets) and our regulatory assets related to generation.
The Texas Electric Restructuring Law prescribes specific methods for determining
the amount of stranded costs and the details for their recovery, and our
recovery of stranded costs is dependent upon the outcome of regulatory
proceedings in which we will be required to establish the extent of our stranded
costs and related underlying matters. During the base rate freeze period from
July 1999 through 2001, earnings above the utility's authorized rate of return
formula were applied in a manner to accelerate depreciation of generation
related plant assets for regulatory purposes. In addition, depreciation expense
for transmission and distribution related assets was redirected to generation
assets for regulatory purposes from 1998. The Texas Electric Restructuring Law
also provided for us, or a special purpose entity formed by us, to issue
securitization bonds for the recovery of generation related regulatory assets
and a portion of stranded costs. Reliant Energy Transition Bond Company LLC, our
wholly owned subsidiary, issued $749 million of securitization bonds on October
24, 2001. Any stranded costs not recovered through the sale of securitization
bonds may be recovered through a charge to transmission and distribution
customers. For additional information regarding these securitization bonds,
please read Note 4(a) to our consolidated financial statements. For information
regarding recovery of under-collected fuel expenses, please read "Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Fuel Filing in Item 7 of
this Form 10-K".
The Texas Utility Commission issued a final order on October 3, 2001
(October 3, 2001 Order) that established the transmission and distribution rates
that became effective January 2002. In this Order, the Texas Utility Commission
found that we had overmitigated our stranded costs by redirecting transmission
and distribution depreciation and by accelerating depreciation of generation
assets as provided under the Transition Plan and Texas Electric Restructuring
Law. In December 2001, we recorded a regulatory liability of $1.1 billion to
reflect the prospective refund of accelerated depreciation, removed our
previously recorded embedded regulatory asset of $841 million related to
redirected depreciation and recorded a regulatory asset of $2.0 billion based
upon current projections of market value of the Reliant Energy HL&P generation
assets to be covered by the 2004 true-up proceeding provided for in the Texas
Electric Restructuring Law. Recovery of this asset is subject to regulatory
risk. We began refunding the excess mitigation credits in January 2002 and will
continue over a seven year period. If events occur that make the recovery of all
or a portion of the regulatory assets no longer probable, we will write off the
corresponding balance of these assets as a charge against earnings. One of the
results of discontinuing the application of regulatory accounting for the
generation operations is the elimination of the regulatory accounting effects of
excess deferred income taxes and investment tax credits related to these
operations. We believe it is probable that some parties will seek to return
these amounts to ratepayers and, accordingly, we have recorded an offsetting
liability.
The Texas Electric Restructuring Law requires us to auction 15% of the
output of the installed generating capacity of our Texas generation business
until January 1, 2007 unless certain criteria are met (state mandated auctions).
In addition, the master separation agreement between Reliant Energy and Reliant
Resources requires us to auction to third parties, including Reliant Resources,
the capacity available in excess of amounts included in the state mandated
auctions (contractually mandated auctions). Beginning January 2002, our Texas
generation business began delivering power sold through the state mandated
auctions and contractually mandated auctions at market rates. However, the Texas
Electric Restructuring Law provides for recovery of any difference between
market power prices received in these capacity auctions and the Texas Utility
Commission's earlier estimates of those market prices. This capacity auction
true-up should provide for revenues earned by our Texas generation business
during the two-year period ending December 2003 to approximate a regulated
return on the invested capital of our Texas generation business. The Texas
Utility Commission's estimate serves as a preliminary identification of stranded
costs for recovery through securitization. This component of the true-up is
intended to ensure that neither the customers nor we are disadvantaged
economically as a result of the two-year transition period by providing this
pricing structure. The underlying data for the true-up calculation has not been
finalized. Because the capacity true-up process provided for in the Texas
Electric Restructuring Law will take into account only the prices we receive in
the state mandated auctions, lower prices that we may receive in the
contractually mandated auctions will not be considered and
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we may therefore not recover all of our stranded costs. We cannot predict the
amount, if any, of these costs that would not be recovered.
Retail. For a discussion of factors affecting our retail operations,
please read "-- Factors Affecting the Results of Our Retail Operations."
Other. For additional information regarding litigation over franchise
fees, please read Note 14(f) to our consolidated financial statements.
FACTORS AFFECTING THE RESULTS OF RERC'S OPERATIONS
Natural Gas Distribution. Our Natural Gas Distribution business segment
competes primarily with alternate energy sources such as electricity and other
fuel sources. In some areas, intrastate pipelines, other gas distributors and
marketers also compete directly with our Natural Gas Distribution business
segment for gas sales to end-users. In addition, as a result of federal
regulatory changes affecting interstate pipelines, natural gas marketers
operating on these pipelines may be able to bypass our Natural Gas Distribution
business segment's facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers.
Generally, the regulations of the states in which our Natural Gas
Distribution business segment operates allow us to pass through changes in the
costs of natural gas to our customers through purchased gas adjustment
provisions in rates. There is, however, an inherent timing difference between
our purchases of natural gas and the ultimate recovery of these costs.
Consequently, we may incur additional "carrying" costs as a result of this
timing difference and the resulting, temporary under-recovery of our purchased
gas costs. To a large extent, these additional carrying costs are not recovered
from our customers.
On November 21, 2001, Arkla filed a rate case (Docket 01-243-U) with the
Arkansas Public Service Commission seeking an increase in rates for its Arkansas
customers of approximately $47 million on an annual basis. Arkla's last rate
increase was authorized in 1995. In the rate filing, Arkla maintains that its
rate base has grown by $183 million, and its operating expenses have increased
from $93 million to $106 million on an annual basis and, therefore, Arkla's
current rates for service to Arkansas customers do not provide a reasonable
opportunity for Arkla to cover its operating costs and earn a fair return on its
investment. A decision in the case is expected by the fourth quarter of 2002.
Pipelines and Gathering. Our Pipelines and Gathering business segment
competes with other interstate and intrastate pipelines in the transportation
and storage of natural gas. The principal elements of competition among
pipelines are rates, terms of service, and flexibility and reliability of
service. Our Pipelines and Gathering business segment competes indirectly with
other forms of energy available to its customers, including electricity, coal
and fuel oils. The primary competitive factor is price. Changes in the
availability of energy and pipeline capacity, the level of business activity,
conservation and governmental regulations, the capability to convert to
alternative fuels, and other factors, including weather, affect the demand for
natural gas in areas we serve and the level of competition for transportation
and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales
activity has been minimal. Commodity transactions are usually related to system
management activity which we have been able to manage with little exposure. We
have not been nor do we anticipate being negatively impacted by higher price
levels and the tightening of supply experienced in the fourth quarter of 2000
and the first quarter of 2001. In addition, competition for our gathering
operations is impacted by commodity pricing levels in its markets because these
prices influence the level of drilling activity in those markets.
Natural Gas Pipeline Company of America has proposed, and is soliciting
customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point
17 miles east of St. Louis Metro, with a proposed in-service date of June 2002.
This service would represent an alternative to that provided by MRT. MRT has
renewed or is engaged in negotiations to renew service agreements under
multi-year terms, including service and potential expansion needs along MRT's
existing East Line in Illinois. Our Pipelines and Gathering business segment
derives approximately 14% of its revenues from Laclede Gas Company, which has an
annual evergreen term provision. In February 2002, MRT negotiated an agreement
to extend its existing service relationship with Laclede for a five year period
subject to acceptance by the FERC. However, the Pipelines and Gathering
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business segment's financial results could be materially adversely affected
after this five year period if Laclede decides to engage another pipeline for
the transportation services currently provided by the Pipelines and Gathering
business segment.
FACTORS AFFECTING THE RESULTS OF OUR WHOLESALE ENERGY OPERATIONS
Price Volatility. Our Wholesale Energy business segment, which is
conducted through Reliant Resources, sells electricity from its facilities into
spot markets under short- and long-term contractual arrangements. We are not
guaranteed any rate of return on our capital investments through cost of service
rates, and our revenues and results of operations are likely to depend, in large
part, upon prevailing market prices for electricity and fuel in our regional
markets. In addition to our power generation operations, we trade and market
power. Market prices may fluctuate substantially over relatively short periods
of time. Demand for electricity can fluctuate dramatically, creating periods of
substantial under- or over-supply. During periods of over-supply, prices are
depressed. During periods of under-supply, there is frequently regulatory or
political pressure to regulate prices to compensate for product scarcity.
In addition, the FERC, which has jurisdiction over wholesale power rates,
as well as independent system operators that oversee some of these markets, have
imposed price limitations, bidding rules and other mechanisms to attempt to
address some of the volatility in these markets and mitigate market prices. For
a discussion of the implementation of price limitations and other rules in the
California market, please read Note 14(g) to our consolidated financial
statements.
Most of our Wholesale Energy business segment's domestic power generation
facilities purchase fuel under short-term contracts or on the spot market. Fuel
prices may also be volatile, and the price we can obtain for power sales may not
change at the same rate as changes in fuel costs. In addition, we trade and
market natural gas and other energy-related commodities. These factors could
have an adverse impact on our revenues, margins and results of operations.
Volatility in market prices for fuel and electricity may result from:
- weather conditions;
- seasonality;
- forced or unscheduled plant outages;
- addition of generating capacity;
- changes in market liquidity;
- disruption of electricity or gas transmission or transportation,
infrastructure or other constraints or inefficiencies;
- availability of competitively priced alternative energy sources;
- demand for energy commodities and general economic conditions;
- availability and levels of storage and inventory for fuel stocks;
- natural gas, crude oil and refined products, and coal production levels;
- natural disasters, wars, embargoes and other catastrophic events; and
- federal, state and foreign governmental regulation and legislation.
Risks Associated with Our Hedging and Risk Management Activities. To lower
our financial exposure related to commodity price fluctuations, our trading,
marketing and risk management services operations routinely enter into contracts
to hedge a portion of our purchase and sale commitments, exposure to weather
fluctuations, fuel requirements and inventories of natural gas, coal, crude oil
and refined products, and other commodities. As part of this strategy, we
routinely utilize fixed-price forward physical purchase and sales contracts,
futures, financial swaps and option contracts traded in the over-the-counter
markets and on exchanges. However, we do not expect to cover the entire exposure
of our assets or our positions to market price volatility, and the coverage will
vary over time. This hedging activity fluctuates according to strategic
objectives, taking into account the desire for cash flow or earnings certainty
and our view on market prices. To the extent we have unhedged positions,
fluctuating commodity prices could negatively impact our financial
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results and financial position. For additional information regarding the
accounting treatment for our hedging, trading and marketing and risk management
activities, please read Notes 2(d) and 5 to our consolidated financial
statements. For additional information regarding the types of contracts and
activities of our trading and marketing operations, please read "-- Trading and
Marketing Operations" and "Qualitative and Quantitative Disclosures about Market
Risk" in Item 7A of this Form 10-K.
We manage our power generation hedge objectives in the context of market
conditions while targeting certain hedge percentages of future earnings through
hedge actions in the current year. As of December 31, 2001, we had hedged 39%
and 29% of our planned Wholesale Energy margins for 2002 and 2003, respectively,
excluding margins related to Orion Power. Margins for 2002 and 2003 are expected
to be positively impacted by the acquisition of Orion Power and negatively
affected by lower forward electric power prices as they relate to unhedged
positions and an estimated decline in our trading and marketing operations due
to projected decreases in volatility in energy commodity markets.
At times, we have open trading positions in the market, within established
corporate risk management guidelines, resulting from the management of our
trading portfolio. To the extent open trading positions exist, changes in
commodity prices could negatively impact our financial results and financial
position.
The risk management procedures we have in place may not always be followed
or may not always work as planned. As a result of these and other factors, we
cannot predict with precision the impact that our risk management decisions may
have on our businesses, operating results or financial position. For information
regarding our risk management policies, please read "Quantitative and
Qualitative Disclosures about Market Risk -- Risk Management Structure" in Item
7A to this Form 10-K.
The trading, marketing and risk management services operations conducted by
our Wholesale Energy business segment are also exposed to the risk that
counterparties who owe us money or physical commodities, such as power, natural
gas or coal, will not perform their obligations. Should the counterparties to
these arrangements fail to perform, we might be forced to acquire alternative
hedging arrangements or replace the underlying commitment at then-current market
prices. In this event, we might incur additional losses to the extent of
amounts, if any, already paid to the counterparties. For information regarding
our credit risk, including exposure to Enron and utilities in California, please
read "Quantitative and Qualitative Disclosure About Market Risk -- Credit Risk"
in Item 7A of this Form 10-K and Notes 5(c), 14(g) and 21 to our consolidated
financial statements.
In the ordinary course of business, and as part of our hedging strategy, we
enter into long-term sales arrangements for power, as well as long-term purchase
arrangements. For information regarding our long-term fuel supply contracts,
purchase power and electric capacity contracts and commitments, electric energy
and electric sale contracts and tolling arrangements, please read Notes 5, 14(a)
and 14(b) to our consolidated financial statements.
Uncertainty in the California Market. During portions of 2000 and 2001,
prices for wholesale electricity in California increased dramatically as a
result of a combination of factors, including higher natural gas prices and
emission allowance costs, reduction in available hydroelectric generation
resources, increased demand, decreased net electric imports and limitations on
supply as a result of maintenance and other outages. Because of the high prices
that prevailed during this period, we, and several of Reliant Resources'
subsidiaries, including Reliant Energy Services and REPG, as well as some of the
officers of some of these companies, have been named as defendants in class
action lawsuits and other lawsuits filed against a number of companies that own
generation plants in California and other sellers of electricity in California
markets.
In response to the filing of a number of complaints challenging the level
of these wholesale prices, the FERC initiated a staff investigation and issued a
number of orders implementing a series of wholesale market reforms and
modifications to those reforms. On February 13, 2002, the FERC issued an order
initiating a staff investigation into potential manipulation of electric and
natural gas prices in the West region for the period January 1, 2000 forward.
Some of our long-term bilateral contracts already have been challenged by one of
our many counterparties based on the alleged market dysfunction in Western power
markets in 2000 and 2001. If these challenges are successful, the precedent set
by the challenge could have larger ramifications to our
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business and operations beyond the challenged contracts at issue. Furthermore,
in addition to FERC investigations, several state and other federal regulatory
investigations have commenced in connection with the wholesale electricity
prices in California and other neighboring Western states to determine the
causes of the high prices and potentially to recommend remedial action.
Finally, there have been proposals in the California state legislature to
regulate the operations of our California generating subsidiaries, beyond the
existing state regulation regarding siting, environmental and other health and
safety matters. For additional information regarding the litigation and market
uncertainty in California, please read Notes 14(f) and 14(g) to our consolidated
financial statements.
Industry Restructuring, the Risk of Re-regulation and the Impact of Current
Regulations. The regulatory environment applicable to the United States
electric power industry is undergoing significant changes as a result of varying
restructuring initiatives at both the state and federal levels and the
reassessment of existing regulatory mechanisms stemming from the California
power market situation and the bankruptcy of Enron. These initiatives have had a
significant impact on the nature of the industry and the manner in which its
participants conduct their business. These changes are ongoing and we cannot
predict the future development of restructuring 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, new laws
and regulations may be adopted or become applicable to us, our facilities or our
commercial activities, and future changes in laws and regulations may have a
detrimental effect on our business. Some restructured markets, particularly
California, have experienced supply problems and price volatility. These supply
problems and volatility have been the subject of a significant amount of press
coverage, much of which has been critical of the restructuring initiatives. In
some markets, including California, proposals have been made by governmental
agencies and/or other interested parties to delay or discontinue proposed
restructuring or to re-regulate areas of these markets, especially with respect
to residential retail customers, that have previously been deregulated. In this
connection, state officials, the California Independent System Operator (Cal
ISO) and the investor-owned utilities in California have argued to the FERC that
our California generating subsidiaries should not continue to have market-based
rate authority. While the FERC to date has consistently refused petitions to
force entities with market-based rates to return to cost-based rates, some of
these proceedings are ongoing and we cannot predict what action the FERC may
take on such petitions in the future. If we were forced to adopt cost-based
rates, future earnings would be affected. Furthermore, the Cal ISO is
undertaking a market redesign process to fundamentally change the structure of
wholesale electricity markets and transmission service in California. These
changes, if approved by the FERC, could include a revised market monitoring and
mitigation structure, a revised congestion management mechanism and an
obligation for load-serving entities in California to maintain capacity
reserves. The Cal ISO's stated goal is to complete the first phase of this
redesign by September 30, 2002, when the existing FERC market mitigation scheme
for California will expire.
On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including Reliant Energy. For information
regarding this FERC proceeding and other FERC actions relating to the California
market, please read Note 14(g) to our consolidated financial statements. If the
FERC does not modify or reject its proposed approach for dealing with
anti-competitive behavior, our future earnings may be affected by the open-ended
refund obligation.
Additionally, federal legislative initiatives have been introduced and
discussed to address the problems being experienced in some of these markets,
including legislation seeking to impose price caps on sales. We cannot predict
whether other proposals to re-regulate will be made or whether legislative or
other attention to the restructuring of the electric power industry will cause
the restructuring to be delayed or reversed. If the trend towards competitive
restructuring of the wholesale power markets is reversed, discontinued or
delayed, the business growth prospects and financial results of our Wholesale
Energy and Retail Energy segments could be adversely affected.
If RTOs are established as envisioned by Order No. 2000, "rate pancaking,"
or multiple transmission charges that apply to a single point-to-point delivery
of energy will be eliminated within a region, and
9
wholesale transactions within the region, and between regions will be
facilitated. The end result could be a more competitive, transparent market for
the sale of energy and a more economic and efficient use and allocation of
resources; however, considerable opposition exists to the development of RTOs.
The FERC also has initiated a rulemaking proceeding to establish
standardized transmission service throughout the United States, a standard
wholesale electric market design, including forward and spot markets for energy
and an ancillary services market, and specifications regarding the entities that
administer these markets and for market monitoring and mitigation, that could be
used in all RTOs. We cannot predict at this time what effect FERC's standard
market design will have on our business growth prospects and financial results.
Partly in response to the bankruptcy of Enron, there have been proposals in
the United States Congress to make online platforms that trade energy and metals
derivatives subject to oversight by the Commodities Futures Trading Commission
(CFTC), to prohibit market price manipulation and fraud. Under some of these
proposals, dealers in energy derivatives would be required to file reports with
the CFTC and maintain amounts of capital, as determined by the CFTC, to support
the risks of their transactions. Other proposals would require the CFTC to
review these markets for potential regulatory recommendations. We do not know
what impact, if any, these proposals would have on our business if enacted.
Additionally, there may be other broader proposals introduced to submit energy
trading to comprehensive regulation by the FERC or by the CFTC.
The acquisition, ownership and operation of power generation facilities
require numerous permits, approvals and certificates from federal, state and
local governmental agencies. The operation of our generation facilities must
also comply with environmental protection and other legislation and regulations.
At present, we have operations in Arizona, California, Florida, Illinois,
Maryland, Nevada, New Jersey, New York, Ohio, Pennsylvania, Texas and West
Virginia. Most of our existing domestic generation facilities are exempt
wholesale generators that sell electricity exclusively into the wholesale
market. These facilities are subject to regulation by the FERC regarding rate
matters and by state public utility commissions regarding siting, environmental
and other health and safety matters. The FERC has authorized us to sell our
generation from these facilities at market prices. The FERC retains the
authority to modify or withdraw our market-based rate authority and to impose
"cost of service" rates if it determines that market pricing is not in the
public interest.
Uncertainty Related to the New York Regulatory Environment. The New York
market is subject to significant regulatory oversight and control. Our operating
results are as dependent on the continuance of the regulatory structure as they
are on fluctuations in the market price for electricity. The rules governing the
current regulatory structure are subject to change. We cannot assure you that we
will be able to adapt our business in a timely manner in response to any changes
in the regulatory structure, which could have a material adverse effect on our
revenues and costs. The primary regulatory risk in this market is associated
with the oversight activity of the New York Public Service Commission, the New
York Independent System Operator (NYISO) and the FERC.
Our assets located in New York are subject to "lightened regulation" by the
New York Public Service Commission, including provisions of the New York Public
Service Law that relate to enforcement, investigation, safety, reliability,
system improvements, construction, excavation, and the issuance of securities.
Because "lightened regulation" was accomplished administratively, it could be
revoked.
The NYISO has the ability to revise wholesale prices, which could lead to
delayed or disputed collection of amounts due to us for sales of energy and
ancillary services. The NYISO also has the ability, in some cases subject to
FERC approval, to impose cost-based pricing and/or price caps. The NYISO has
implemented a measure known as the "Automated Mitigation Procedure" (AMP) under
which day-ahead energy bids will be automatically reviewed and, if necessary,
mitigated if economic or physical withholding is determined. Proposed
modifications to the AMP provide a level of uncertainty over the impacts of that
procedure in the summer of 2002. FERC has also directed the NYISO to adopt
mitigation measures for all limits in New York City consistent with its overall
market-monitoring plan. NYISO has filed in-city mitigation measures with the
FERC, which it is proposing to be implemented beginning in late spring of 2002.
The full impact of these revisions may not be known until the summer of 2002.
10
Integration and Other Risks Associated with Our Orion Power Assets. We
have made a substantial investment in our recent acquisition of Orion Power. If
we are unable to profitably integrate, operate, maintain and manage our newly
acquired power generation facilities our results of operations will be adversely
affected.
Duquesne Light Company is obligated to supply electricity at predetermined
tariff rates to all retail customers in its existing service territory who do
not select another electricity supplier. Orion Power has committed to provide
100% of the energy that Duquesne Light Company needs to meet this obligation
under a contract that was recently extended through December 2004. If our
obligation under this contract exceeds the available output from the combination
of Orion Power's generation facilities and our additional generation facilities
in the region, we would be forced to buy additional energy at prevailing market
prices and, in certain cases where we failed to deliver the required amount, we
could incur penalties during periods of peak demand of up to $1,000 per megawatt
hour. If this situation were to occur during periods of peak energy prices, we
could suffer substantial losses that could materially adversely affect our
results of operations. In addition, our revenues generated under this contract
may be adversely impacted if a substantial number of Duquesne Light Company's
retail customers select other retail electric providers.
Operating Risks. Our Electric Generation, Wholesale Energy operations and
our European Energy operations are exposed to risks relating to the breakdown or
failure of equipment or processes, fuel supply interruptions, shortages of
equipment, material and labor, and operating performance below expected levels
of output or efficiency. A significant portion of our facilities were
constructed many years ago. Older generating equipment, even if maintained in
accordance with good engineering practices, may require significant capital
expenditures to add or upgrade equipment to keep it operating at peak
efficiency, to comply with changing environmental requirements, or to provide
reliable operations. Such changes could affect operating costs. Any unexpected
failure to produce power, including failure caused by breakdown or forced
outage, could result in reduced earnings.
We depend on transmission and distribution facilities owned and operated by
utilities and other power companies to deliver the electricity we sell from our
power generation facilities to our customers, who in turn deliver these products
to the ultimate consumers of the power. If transmission is disrupted, or
transmission capacity is inadequate, our ability to sell and deliver our
products may be hindered.
Factors Affecting Our Acquisition and Project Development Activities. Our
plans for our Wholesale Energy business segment indicate a shift in emphasis
from identifying and pursuing acquisition and development candidates to
construction and integration of generation facilities. We believe this is a
temporary shift based on the requirements of integrating the Orion Power assets
and the maturation of both our and Orion Power's development projects and by the
current state of the wholesale electricity and capital markets.
There are numerous risks relating to the acquisition and development of
power generation plants and construction and integration of these facilities. We
may not be able to identify attractive acquisitions or development
opportunities, complete acquisitions or development projects we undertake, or we
may not be able to integrate these plants, especially larger acquisitions, into
the portfolios of our Wholesale Energy business segment and achieve the
synergies, including cost savings, we originally envisioned.
Currently, our Wholesale Energy business segment has a select number of
power generation facilities under development and many under construction
(either owned or leased). Our completion of these facilities is subject to the
following:
- market prices;
- shortages and inconsistent quality of equipment, material and labor;
- financial market conditions and the results of our financing efforts;
- actions by rating agencies with respect to us or our competitors;
- work stoppages, due to plant bankruptcies and contract labor disputes;
- permitting and other regulatory matters;
11
- unforeseen weather conditions;
- unforeseen equipment problems;
- environmental and geological conditions; and
- unanticipated capital cost increases.
Any of these factors could give rise to delays, cost overruns or the
termination of the plant expansion, construction or development. Many of these
risks cannot be adequately covered by insurance. While we maintain insurance,
obtain warranties from vendors and obligate contractors to meet specified
performance standards, the proceeds of such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues, increased expenses or
liquidated damages payments we may owe.
If we were unable to complete the development of a facility, we would
generally not be able to recover our investment in the project. The process for
obtaining initial environmental, siting and other governmental permits and
approvals is complicated, expensive, lengthy and subject to significant
uncertainties. Transmission interconnection, fuel supply and cooling water
represent some cost uncertainties during project development that may also
result in termination of the project. In addition, construction delays and
contractor performance shortfalls can result in the loss of revenues and may, in
turn, adversely affect our results of operations. The failure to complete
construction according to specifications can result in liabilities, reduced
plant efficiency, higher operating costs and reduced earnings. We may not be
successful in the development or construction of power generation facilities in
the future.
As a result of several recent events, including the United States economic
recession, the price decline of our industry sector in the equity capital
markets and the downgrading of the credit ratings of several of our significant
competitors, the availability and cost of capital for our business and the
businesses of our competitors has been adversely affected. In response to these
events and the intensified scrutiny of companies in our industry sector by the
rating agencies, our Wholesale Energy business segment has reduced its planned
capital expenditures by $2.7 billion over the 2002-2006 time frame.
Successful integration of plants, especially acquisitions, is subject to a
number of risks, including the following:
- unforeseen liabilities or other exposures;
- inaccurate due diligence of acquired facilities, such as underestimates
of outage rates and operating costs;
- inability to achieve adequate cost savings in both overhead and
operations;
- inability to achieve various commercial synergies with existing
operations; and
- market prices for power and fuels.
Any of these factors could significantly affect the economic impact of an
acquisition on our results of operations.
As part of this integration process and our temporary shift in emphasis,
the Orion Power plants will be part of an operations improvement process that
strives to achieve both reduced operating and maintenance costs and increase
gross margins through improved availability and reliability of plants. This
process is currently underway at our other plants and will be introduced at the
Orion Power facilities beginning in the third quarter of 2002.
Increasing Competition in Our Industry. Our Wholesale Energy business
segment competes with other energy merchants. In order to successfully compete,
we must have the ability to aggregate supplies at competitive prices from
different sources and locations and must be able to efficiently utilize
transportation services from third-party pipelines and transmission services
from electric utilities. We also compete against other energy merchants on the
basis of our relative skills, financial position and access to credit sources.
Energy customers, wholesale energy suppliers and transporters often seek
financial guarantees and other
12
assurances that their energy contracts will be satisfied. As pricing information
becomes increasingly available in the energy trading and marketing business, we
anticipate that our operations will experience greater competition and downward
pressure on per-unit profit margins. Furthermore, demands for liquidity to
support trading and merchant asset businesses are increasing at the same time
that the credit rating agencies are reviewing the liquidity and other credit
criteria for trading, marketing and merchant generation firms. Other companies
we compete with may not have similar credit ratings pressure or may have higher
credit ratings. The growth of electronic trading platforms has increased the
number of transactions, potential counterparties and level of price transparency
in the energy commodity market. As a result, we are likely to transact with a
wide range of customers potentially increasing our risk due to their changing
credit circumstances, while at the same time potentially diversifying our
reliance on a smaller number of customers.
Developments with respect to our competitors frequently have a collateral
and tangible impact on us. Credit and liquidity concerns impact our ability to
do business with counterparties. Adverse regulatory and political ramifications
can result from activities and investigations directed at our competitors.
Hydroelectric Facilities Licensing. The Federal Power Act gives the FERC
exclusive authority to license non-federal hydroelectric projects on navigable
waterways and federal lands. The FERC hydroelectric licenses are issued for
terms of 30 to 50 years. Some of the hydroelectric facilities in our Wholesale
Energy business segment, representing approximately 90 MW of capacity, have
licenses that expire within the next ten years. Facilities that we own
representing approximately 160 MW of capacity have new or initial license
applications pending before the FERC. Upon expiration of a FERC license, the
federal government can take over the project and compensate the licensee, or the
FERC can issue a new license to either the existing licensee or a new licensee.
In addition, upon license expiration, the FERC can decommission an operating
project and even order that it be removed from the river at the owner's expense.
In deciding whether to issue a license, the FERC gives equal consideration to a
full range of licensing purposes related to the potential value of a stream or
river. It is not uncommon for the relicensing process to take between four and
ten years to complete. Generally, the relicensing process begins at least five
years before the license expiration date and the FERC issues annual licenses to
permit a hydroelectric facility to continue operations pending conclusion of the
relicensing process. We expect that the FERC will issue to us new or initial
hydroelectric licenses for all the facilities with pending applications.
Presently, there are no applications for competing licenses and there is no
indication that the FERC will decommission or order any of the projects to be
removed.
FACTORS AFFECTING THE RESULTS OF OUR EUROPEAN ENERGY OPERATIONS
General. Our European Energy segment, which is operated by subsidiaries of
Reliant Resources, intends to focus its activities in existing trading markets
in the Netherlands, the United Kingdom, Germany, the Scandinavian countries,
Austria and Switzerland. Historical results of operations may not be indicative
of future results of operations. In particular, results of operations for our
European Energy segment prior to 2001 reflect the impact of a regulated
generation price system that has been discontinued. In addition, in 2001 and
prior years, under Dutch corporate income tax laws, the earnings of REPGB were
subject to a zero percent Dutch corporate income tax rate as a result of the
Dutch tax holiday applicable to its electric industry. After December 31, 2001,
all of European Energy's earnings in the Netherlands will be subject to the
standard Dutch corporate income tax rate, which currently is 34.5%. Furthermore,
European Energy's results of operations for 2001 include the effect of a number
of non-recurring items, including the $37 million net gain resulting from the
settlement of a stranded cost indemnity agreement.
Future results of operations of our European Energy segment could be
affected by, among other things, the following:
- increasing competition in the Dutch wholesale energy market, resulting in
declining electric power margins;
- the timing and pace of the deregulation of other sectors of the European
energy markets;
- the continuing negative impact of the bankruptcy of Enron on market
liquidity and credit requirements in European trading markets;
13
- the mark-to-market price risk exposure associated with certain stranded
cost electricity and natural gas supply contracts;
- the impact of any renegotiation of European Energy's stranded cost
contracts;
- the impact and changes of natural gas tariffs pursuant to changes in the
regulatory structure;
- the ability to negotiate new contracts or renew contracts with customers
on favorable terms; and
- the impact of slowing economic growth on power generation demand in the
markets in which our European Energy segment operates.
Competition in the European Market. Competition for energy customers in
the markets in which our European Energy segment operates is high. The primary
factors affecting our European Energy segment's competitive position are price,
regulation, the economic resources of its competitors, and its market reputation
and perceived creditworthiness.
Our European Energy segment competes in the Dutch Wholesale market against
a variety of other companies, including other Dutch generation companies,
cogenerators, various producers of alternate sources of power and non-Dutch
generators of electric power, primarily from France and Germany. As of December
31, 2001, the Dutch electricity system had three operational interconnection
points with Germany and two interconnection points with Belgium. There are also
a number of projects that are at various stages of development and that may
increase the number of interconnections in the future (post 2005), including
interconnections with Norway and the United Kingdom. The Belgian
interconnections are primarily used to import electricity from France, but a
larger portion of Dutch electricity imports comes from Germany. It is
anticipated that over time, transmission constraints between the Netherlands and
other European markets will be reduced, thereby exposing our European Energy
segment to even greater competitive pressures.
Our European Energy segment's trading and marketing operations are also
subject to increasing levels of competition. Competition among power generators
for customers is intense and is expected to increase as more participants enter
increasingly deregulated markets. Many of our European Energy segment's existing
competitors have geographic market positions far more extensive than that of our
European Energy segment. In addition, many of these competitors possess
significantly greater financial, personnel and other resources than our European
Energy segment.
Deregulation of the Dutch Market. The Dutch wholesale electric market was
completely opened to competition on January 1, 2001. Consistent with our
expectations at the time we acquired our operations in the Netherlands, the
gross margin of our European Energy segment declined in 2001 as a result of the
deregulation of the market and the termination of an agreement with the other
Dutch generators and the Dutch distributors. Commercial markets were generally
opened to retail competition in January 2002. We expect the remainder of the
market, consisting of mainly residential customers, will be open to competition
by January 1, 2003. The timing of opening of the residential segment of the
market is subject to change, however, at the discretion of the Dutch Minister of
Economic Affairs. Since our European Energy segment's operations focus on the
wholesale market, we do not expect that the opening of the Dutch commercial or
residential electric market will have a significant impact on the segment's
results of operations.
Plant Outages. During 2001, our margins were negatively impacted by
unplanned outages at some of our Dutch generation facilities. The unplanned
outages were primarily due to malfunctions of the generation turbines and
related equipment and complications encountered in the maintenance of one of our
facilities. We estimate that these unplanned outages resulted in losses of
approximately $11 million, a significant portion of which is covered by property
damage and business interruption insurance. For additional information regarding
operational risks applicable to our European Energy segment, including unplanned
plant outages, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Operating Risks."
Other Factors. In December 2001, REPGB and its former shareholders entered
into a settlement agreement resolving the former shareholders' stranded cost
indemnity obligations under the purchase agreement of REPGB. For additional
information regarding the stranded cost indemnity settlement and the potential
impact on earnings from changes in the valuation in the future of the related
stranded cost contracts,
14
please read Notes 5(b) and 14(h) to our consolidated financial statements. We
have begun discussions with the other parties to these contracts to modify the
terms of certain of the out-of-market contracts. The structure of these
settlements, if consummated, likely would entail an upfront cash payment to the
counterparty in exchange for amendments to price and other terms intended to
make the contracts more market conforming. REPGB would seek to fund these
payments, if made, to the extent possible through the proceeds from the
settlement of its stranded cost indemnity agreement and, possibly, anticipated
distributions from NEA. We cannot currently predict the outcome of these
negotiations. However, to the extent that these discussions result in amendments
to the contracts, we could realize a gain.
We are in the process of reviewing our European Energy segment's goodwill
and certain intangibles for impairment pursuant to SFAS No. 142. For information
regarding assessing the impairment in 2002 under SFAS No. 142, please read
"-- New Accounting Pronouncements."
Our European operations are subject to various risks incidental to
investing or operating in foreign countries. These risks include economic risks,
such as fluctuations in currency exchange rates, restrictions on the
repatriation of foreign earnings and/or restrictions on the conversion of local
currency earnings into U.S. dollars. For example, we estimate that the impact of
the devaluation of the Euro relative to the U.S. dollar during 2001 negatively
affected U.S. dollar net income by approximately $2 million.
FACTORS AFFECTING THE RESULTS OF OUR RETAIL ENERGY OPERATIONS
General. The Texas retail electricity market fully opened to competition
in January 2002. Therefore, we do not expect the earnings from our Retail Energy
segment, which is operated by subsidiaries of Reliant Resources, for past years
to be indicative of our future earnings and results. The level of future
earnings generated by our Retail Energy segment will depend on numerous factors
including:
- legislative and regulatory developments related to the newly opened
retail electricity market in Texas and changes in the application of such
laws and regulations;
- the effects of competition, including the extent and timing of the entry
or exit of competitors in our markets and the impact of competition on
retail prices and margins;
- customer attrition rates and cost associated with acquiring and retaining
new customers;
- our ability to negotiate new contracts or renew contracts with customers
on favorable terms;
- the timing and extent of changes in wholesale commodity prices and
transmission and distribution rates;
- our ability to procure adequate electricity supply upon economic terms;
- our ability to effectively hedge commodity prices;
- our ability to pass increased supply costs on to customers in a timely
manner;
- our ability to timely perform our obligations under our customer
contracts;
- market liquidity for wholesale power;
- the financial condition and payment patterns of our customers;
- weather variations and other natural phenomena;
- the timely and accurate implementation of the new internal and external
information technology systems and processes necessary to provide
customer information and to implement customer switching in the retail
electricity market in Texas which was established in late 2001;
- the costs associated with operating our internal customer service and
other operating functions; and
- the timing and accuracy of ERCOT settlements, and the exchange of
information between ERCOT, the T&D Utility and our Retail Energy
segment's retail electric provider, which facilitates our Retail Energy
business segment's billing, collection and supply management processes.
15
Competition in the Texas Market. Under the Texas Electric Restructuring
Law, beginning in 2002, all classes of Texas customers of most investor-owned
utilities, and those of any municipal utility and electric cooperative that
opted to participate in the competitive marketplace, are able to choose their
retail electric provider. In January 2002, Reliant Resources began to provide
retail electric services to all customers of Reliant Energy HL&P who did not
select another retail electric provider. Under the market framework established
by the Texas Electric Restructuring Law, Reliant Resources is recognized as the
affiliated retail electric provider of Reliant Energy's electric utility. The
Distribution will not change this treatment, even though Reliant Resources will
cease to be a subsidiary of Reliant Energy after the Distribution. As an
affiliated retail electric provider, Reliant Resources is initially required to
sell electricity to these Houston area residential and small commercial
customers at a specified price, which is referred to in the law as the "price to
beat," whereas other retail electric providers are allowed to sell electricity
to these customers at any price. Reliant Resources' price to beat was set at a
level resulting in an estimated average 17% reduction from December 31, 2001
rates for its residential customers and an estimated average 22% reduction from
December 31, 2001 rates for its pre-existing small commercial customers. The
wholesale energy supply cost component, or "fuel factor," included in its price
to beat was initially set by the Texas Utility Commission at the then average
forward 12 month gas price strip of approximately $3.11/MMBtu.
Reliant Resources is not permitted to offer electricity to these customers
at a price other than the price to beat until January 1, 2005, unless before
that date the Texas Utility Commission determines that 40% or more of the amount
of electric power that was consumed in 2000 by the relevant class of customers
in the Houston metropolitan area is committed to be served by retail electric
providers other than Reliant Resources. In addition, as the affiliated retail
electric provider, Reliant Resources is obligated to offer the price to beat to
requesting residential and small commercial customers in Reliant Energy's
electric utility service territory through January 1, 2007. Because Reliant
Resources will not be able to compete for residential and small commercial
customers on the basis of price in the Houston area, it may lose a significant
number of these customers to other retail electric providers. Customers were
given the opportunity to switch beginning in August 2001 through the retail
pilot project. Due to system related problems which restricted the timely
switching of customers during the pilot project and in early 2002, we cannot be
sure of the number of customers that have attempted to switch to other retail
electric providers. For additional information regarding retail market systems
problems, please read "-- Operational Risks." Between the beginning of the pilot
project in August 2001 and February 28, 2002, Reliant Resources estimates that
approximately 67,000 customers (or approximately 4% of their residential and
small commercial customers) have switched to other retail electric providers.
Due to the switching systems problems, the actual numbers of customers that
switched or attempted to switch by this date may actually be higher.
Reliant Resources is providing commodity service to the large commercial,
industrial and institutional customers previously served by Reliant Energy's
electric utility who did not take action to select another retail electric
provider. In addition, Reliant Resources has signed contracts to provide
electricity and services to large commercial, industrial and institutional
customers, both in the Houston area as well as outside of the Houston market.
Reliant Resources or any other retail electric provider can provide services to
these customers at any negotiated price. The market for these customers is very
competitive, and any of these customers that select Reliant Resources as their
provider may subsequently decide to switch to another provider at the conclusion
of the term of their contract with Reliant Resources.
In most retail electric markets outside the Houston area, Reliant
Resources' principal competitor may be the local incumbent utility company's
retail affiliate. These retail affiliates have the advantage of long-standing
relationships with their customers. In addition to competition from the
incumbent utilities' affiliates, Reliant Resources may face competition from a
number of other retail providers, including affiliates of other non-incumbent
utilities, independent retail electric providers and, with respect to sales to
large commercial and industrial customers, independent power producers acting as
retail electric providers. Some of these competitors or potential competitors
may be larger and better capitalized than Reliant Resources.
Generally, retail electric providers will purchase electricity from the
wholesale generators at unregulated rates, sell electricity to their retail
customers and pay the transmission and distribution utility a regulated tariffed
rate for delivering the electricity to their customers. Retail electric
providers will then bill and collect
16
payments from the customers. Because Reliant Resources is required to sell
electricity to residential and small commercial customers in the Houston area at
the price to beat, it may lose a significant number of these customers to
non-affiliated retail electric providers if their cost to provide electricity to
these customers is lower than the price to beat. In addition, the results of our
Retail Energy operations for sales to residential and small commercial customers
over the next several years in Texas will be largely dependent upon the amount
of gross margin, or "headroom," available in our price to beat. Until 2004, when
Reliant Resources will have the option to acquire our ownership interest in
Texas Genco, Reliant Resources' results will be largely based on the ability of
the Wholesale Energy segment to buy power at prices that yield acceptable gross
margins at revenue levels determined by the price to beat set by the Texas
Utility Commission. The available headroom in the price to beat is equal to the
difference between the price to beat and the sum of the charges, fees and
transmission and distribution utility rates approved by the Texas Utility
Commission and the price Reliant Resources pays for power to serve its price to
beat customers. The larger the amount of headroom, the more incentive new market
entrants should have to provide retail electric services in that particular
market. The Texas Utility Commission's regulations allow affiliated retail
electric providers to adjust their price to beat fuel factor based on the
percentage change in the price of natural gas. In addition, they may also
request an adjustment as a result of changes in their price of purchased energy.
In such a request, they may adjust the fuel factor to the extent necessary to
restore the amount of headroom that existed at the time the initial price to
beat fuel factor was set by the Texas Utility Commission. Affiliated retail
electric providers may not request that their price to beat be adjusted more
than twice a year. Reliant Resources cannot estimate with any certainty the
magnitude and frequency of the adjustments they may seek, if any, and the
eventual impact of such adjustments on the amount of headroom. Based on forward
gas prices at the end of March 2002, Reliant Resources would be able to increase
its price to beat rates by approximately 4-5%. Available headroom in the Houston
market, as well as in other Texas markets where Reliant Resources intends to
compete, will be affected by any changes in transmission and distribution rates
that may be requested by the transmission and distribution provider in the
respective service territory and in taxes, fees and other charges assessed or
levied by third parties. Any changes in transmission and distribution rates must
be approved by the Texas Utility Commission. The Texas Utility Commission has
initiated a proceeding to determine what taxes a municipality or other local
taxing authority can charge retail electric providers relating to the provision
of electricity.
In Texas, our Wholesale Energy business segment and our Retail Energy
business segment work together in order to determine the price, demand and
supply of energy required to meet the needs of our Retail Energy business
segments' customers. Reliant Resources may purchase capacity from non-affiliated
parties in the state mandated auctions and from our Texas generation business in
the contractually mandated auctions. Reliant Resources also enters into
bilateral contracts with third parties for capacity, energy and ancillary
services. Supply positions are continuously monitored and updated based on
retail sales forecasts and market conditions. However, Reliant Resources does
not expect to cover the entire exposure of these positions to market price
volatility, and the coverage will vary over time. For a discussion of risks
similar to those associated with our Retail Energy segment's hedging activities,
please read "-- Factors Affecting the Results of Our Wholesale Energy
Operations -- Price Volatility," and "-- Risks Associated with Our Hedging and
Risk Management Activities." In addition to the factors noted in these sections,
Reliant Resources' ability to adequately hedge its retail electricity
requirements is also dependent on the accurate forecast of the number of our
customers in each customer class and uncertainties associated with the recently
established ERCOT settlement procedures.
Obligations as a Provider of Last Resort. The Texas Electric Restructuring
Law requires the Texas Utility Commission to designate certain retail electric
providers as providers of last resort in areas of the state in which retail
competition is in effect. A provider of last resort is required to offer a
standard retail electric service package for each class of customers designated
by the Texas Utility Commission at a fixed, nondiscountable rate approved by the
Texas Utility Commission, and is required to provide the service package to any
requesting retail customer in the territory for which it is the provider of last
resort. In the event that another retail electric provider fails to serve any or
all of its customers, the provider of last resort is required to offer that
customer the standard retail service package for that customer class with no
interruption of service to the customer. The Texas Utility Commission designated
Reliant Resources' subsidiary, StarEn Power to serve as the provider of last
resort for residential and small commercial customers in the western
17
portion of the Dallas/Fort Worth metropolitan area formally served by Texas
Utilities, Inc., a subsidiary of TXU, Inc. In addition, StarEn Power has been
appointed as the provider of last resort for large commercial, industrial and
institutional customers in Reliant Energy's electric utility service territory.
StarEn Power will serve two consecutive six month terms as the provider of last
resort. The first term began on January 1, 2002. The second six-month term,
beginning July 1, 2002, will include a potential adjustment to the energy
component of our provider of last resort rate based on a NYMEX Henry Hub natural
gas index. The terms and rates for provider of last resort service are governed
by a settlement between Reliant Resources and various interested parties, which
settlement was approved by the Texas Utility Commission. In this role, StarEn
Power retains the rights to require customer deposits and disconnect service in
accordance with Texas Utility Commission rules, and to petition the Texas
Utility Commission for a price change in the event it is determined that StarEn
power will experience a net financial loss over the term of its provider of last
resort obligations. In the first quarter of 2002, the Texas Utility Commission
initiated a proceeding to review and possibly amend both the governing rules and
structure of provider of last resort service and obligations. This proceeding is
in its initial stages and we cannot be sure whether the structure of provider of
last resort service and obligations will change, how they will change or what
effect, if any, any changes would have on the financial condition, results of
operations or cash flows of StarEn Power or our Retail Energy business segment.
"Clawback" Payment to Reliant Energy. To the extent the price to beat
exceeds the market price of electricity, Reliant Resources will be required to
make a payment to Reliant Energy in 2004 unless the Texas Utility Commission
determines that, on or prior to January 1, 2004, 40% or more of the amount of
electric power that was consumed in 2000 by residential or small commercial
customers (at or below one MW), as applicable, within Reliant Energy HL&P's
service territory is committed to be served by retail electric providers other
than Reliant Resources. If the 40% test is not met and the reconciliation and a
retail payment is required, the amount of this retail payment will be equal to
(a) the amount that the price to beat, less non-bypassable delivery charges, is
in excess of the prevailing market price of electricity during such period per
customer, but not to exceed $150 per customer, multiplied by (b) the number of
residential or small commercial customers, as the case may be, that we serve on
January 1, 2004 in Reliant Energy HL&P's service territory, less the number of
new retail electric customers Reliant Resources serves in other areas of Texas.
Amounts received from Reliant Resources with respect to the clawback payment, if
any, will be included in the 2004 stranded cost true-up as a reduction of
stranded costs.
Operational Risks. The price of purchased power could have an adverse
effect on the costs incurred by our Retail Energy segment in acquiring power to
serve the demand of its retail customers. For additional information regarding
commodity price volatility, please read "-- Factors Affecting the Results of Our
Wholesale Energy Operations -- Price Volatility."
Reliant Resources is dependent on local transmission and distribution
utilities for maintenance of the infrastructure through which electricity is
delivered to its retail customers. Any infrastructure failure that interrupts or
impairs delivery of electricity to its customers could negatively impact the
satisfaction of its customers with its service. Additionally, Reliant Resources
is dependent on the local transmission and distribution utilities for the
reading of its customers' energy meters. Reliant Resources is required to rely
on the local utility or, in some cases, the independent transmission system
operator, to provide it with its customers' information regarding energy usage,
and Reliant Resources may be limited in its ability to confirm the accuracy of
the information. The provision of inaccurate information or delayed provision of
such information by the local utilities or system operators could have a
material negative impact on our business and results of operations and cash
flows.
The ERCOT ISO is the independent system operator responsible for
maintaining reliable operations of the bulk electric power supply system in the
ERCOT market. Its responsibilities include ensuring that information relating to
a customer's choice of retail electric provider is conveyed in a timely manner
to anyone needing the information. Problems in the flow of information between
the ERCOT ISO, the transmission and distribution utility and the retail electric
providers have resulted in delays in switching customers. While the flow of
information is improving, operational problems in the new system and processes
are still being worked out.
18
The ERCOT ISO is also responsible for handling scheduling and settlement
for all electricity supply volumes in the Texas deregulated electricity market.
In addition, the ERCOT ISO plays a vital role in the collection and
dissemination of metering data from the transmission and distribution utilities
to the retail electric providers. Reliant Resources and other retail electric
providers schedule volumes based on forecasts. As part of settlement, the ERCOT
ISO communicates the actual volumes delivered compared to the forecast volumes
scheduled. The ERCOT ISO calculates an additional charge or credit based on the
difference between the actual and forecast volumes, utilizing a market clearing
price for the difference. Settlement charges also include allocated costs such
as unaccounted-for energy. Currently, there is a three to four month delay in
receiving the final settlement information. As a result, Reliant Resources must
estimate its supply costs. Timing delays in receiving final settlement
information creates supply cost estimation risk.
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
For information regarding our exposure to risk as a result of fluctuations
in commodity prices and derivative instruments, please read "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K.
ENVIRONMENTAL EXPENDITURES
We are subject to numerous environmental laws and regulations, which
require us to incur substantial costs to operate existing facilities, construct
and operate new facilities, and mitigate or remove the effect of past operations
on the environment. For additional information regarding environmental
contingencies, please read Note 14(f) to our consolidated financial statements.
Clean Air Act Expenditures. We expect the majority of capital expenditures
associated with environmental matters to be incurred by our Electric Generation
and Wholesale Energy business segments in connection with emission limitations
for NOx under the Clean Air Act, or to enhance operational flexibility under
Clean Air Act requirements. In 2000, emission reduction requirements for NOx
were finalized for our electric generating facilities in the United States. We
currently estimate that up to $476 million will be required to comply with the
requirements through the end of 2004, with an estimated $287 million to be
incurred in 2002. The Texas regulations require additional reductions that must
be completed by March 2007. Plans for the Texas units for the period 2004
through 2007 have not been finalized, but have been estimated at $88 million. We
are currently litigating the economic and technical viability of the Texas
post-2004 reduction requirements, but cannot predict the outcome of this
litigation. In addition, the Texas Electric Restructuring Law created a program
mandating air emissions reductions for some generating facilities of our
Electric Generation business segment. The Texas Electric Restructuring Law
provides for stranded cost recovery of costs associated with this obligation
incurred before May 1, 2003. For additional information regarding the Texas
Electric Restructuring Law, please read "-- Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Texas Electric Restructuring
Law" in Item 1 of this Form 10-K and Note 4(a) to our consolidated financial
statements. For additional information regarding environmental regulation of air
emissions, please read "Business -- Environmental Matters -- Air Emissions" in
Item 1 of this Form 10-K.
Site Remediation Expenditures. From time to time we have received notices
from regulatory authorities or others regarding our status as a potentially
responsible party in connection with sites found to require remediation due to
the presence of environmental contaminants. Based on currently available
information, we believe that remediation costs will not materially affect our
financial position, results of operations or cash flows. There can be no
assurance, however, that future developments, including additional information
about existing sites or the identification of new sites, will not require
material revisions to our estimates. For information about specific sites that
are the subject of remediation claims, please read Note 14(f) to our
consolidated financial statements.
Water, Mercury and Other Expenditures. As discussed under
"Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K,
regulatory authorities are in the process of implementing regulations and
quality standards in connection with the discharge of pollutants into waterways.
Once these regulations and quality standards are enacted, we will be able to
determine if our operations are in compliance,
19
or if we will have to incur costs in order to comply with the quality standards
and regulations. Until that time, however, we are not able to predict the amount
of these expenditures, if any. To date, however, our expenditures associated
with respect to permits, registrations and authorizations for operation of
facilities under the statutes regulating the discharge of pollutants into
surface water have not been material. With regard to mercury remediation and
other environmental matters, such as the disposal of solid wastes, our
expenditures have not been, and are not expected to be material, based on our
experiences and that of others in our industries. Please read
"Business -- Environmental Matters -- Mercury Contamination" and "-- Other" in
Item 1 of this Form 10-K.
OTHER FACTORS
Terrorist Attacks and Acts of War. We are currently unable to measure the
ultimate impact of the terrorist attacks of September 11, 2001 on our industry
and the United States economy as a whole. The uncertainty associated with the
retaliatory military response of the United States and other nations and the
risk of future terrorist activity may impact our results of operations and
financial condition in unpredictable ways. These actions could result in adverse
changes in the insurance markets and disruptions of power and fuel markets. In
addition, our generation facilities or the power transmission and distribution
facilities on which we rely could be directly or indirectly harmed by future
terrorist activity. The occurrence or risk of occurrence of future terrorist
attacks or related acts of war could also adversely affect the United States
economy. A lower level of economic activity could result in a decline in energy
consumption which could adversely affect our revenues, margins and limit our
future growth prospects. The occurrence or risk of occurrence could also
increase pressure to regulate or otherwise limit the prices charged for
electricity or gas. Also, these risks could cause instability in the financial
markets and adversely affect our ability to access capital.
Environmental Regulation. Our Electric Generation and Wholesale Energy
business segments are subject to extensive environmental regulation by federal,
state and local authorities. We are required to comply with numerous
environmental laws and regulations, and to obtain numerous governmental permits,
in operating our facilities. We may incur significant additional costs to comply
with these requirements. If we fail to comply with these requirements, we could
be subject to civil or criminal liability and fines. Existing environmental
regulations could be revised or reinterpreted, new laws and regulations could be
adopted or become applicable to us or our facilities, and future changes in
environmental laws and regulations could occur, including potential regulatory
and enforcement developments related to air emissions. If any of these events
occur, our business, operations and financial condition could be adversely
affected.
We may not be able to obtain or maintain from time to time all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if we fail to obtain and comply
with them, the operation of our facilities could be prevented or become subject
to additional costs.
We are generally responsible for all on-site liabilities associated with
the environmental condition of our power generation facilities which we have
acquired and developed, regardless of when the liabilities arose and whether
they are known or unknown. These liabilities may be substantial.
Holding Company Organizational Structure. We are a holding company, and we
conduct a significant portion of our operations through our subsidiaries. After
the Restructuring and Distribution, CenterPoint Energy will be a holding company
that conducts substantially all of its operations through its respective
subsidiaries. CenterPoint Energy's only significant assets will be the capital
stock of its subsidiaries, and its subsidiaries will generate substantially all
of CenterPoint Energy's operating income and cash flow. As a result, dividends
or advances from CenterPoint Energy's subsidiaries will be the principal source
of funds necessary to meet its debt service obligations. In some circumstances,
contractual provisions (including terms of indebtedness) or laws, as well as the
financial condition or operating requirements of our respective subsidiaries,
may limit our or CenterPoint Energy's ability to obtain cash from our respective
subsidiaries. As of December 31, 2001, all conditions on payments to us by our
subsidiaries that are contained in existing agreements were satisfied. After the
Distribution, Reliant Resources will also be a holding company that conducts all
of its operations through its subsidiaries and will be subject to similar
structural limitations as
20
described above with respect to CenterPoint Energy. For information regarding
payment of dividends please read Item 5 of this Form 10-K.
In addition, the ability of REMA, a Reliant Resources subsidiary that owns
some of the power generation facilities in our Northeast regional portfolio, to
pay dividends or make restricted payments to Reliant Resources is restricted
under the terms of three lease agreements under which we lease all or an
undivided interest in these generating facilities. These agreements allow our
Mid-Atlantic subsidiary to pay dividends or make restricted payments only if
specified conditions are satisfied, including maintaining specified fixed charge
coverage ratios.
Liquidity Concerns. For a discussion of factors affecting our sources of
cash and liquidity, please read "-- Liquidity and Capital Resources -- Future
Sources and Uses of Cash."
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOWS
The net cash provided by/used in operating, investing and financing
activities for 1999, 2000 and 2001 is as follows (in millions):
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------
1999 2000 2001
------- ------- -------
Cash provided by (used in):
Operating activities.................................. $ 1,104 $ 1,344 $ 1,713
Investing activities.................................. (2,870) (3,286) (2,085)
Financing activities.................................. 1,823 2,032 337
</Table>
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operations in 2001 increased $369 million compared to
2000. This increase primarily resulted from:
- an increase in recovered fuel costs by our Electric Operations business
segment;
- a decrease in net margin deposits on energy trading activities as a
result of reduced commodity volatility and relative price levels of
natural gas and power compared to the fourth quarter of 2000; and
- an increase in operating margins from Wholesale Energy's power generation
operations.
This increase is partially offset by:
- a prepayment of a lease obligation related to REMA sale/leaseback
transactions (please read Note 14(b) to our consolidated financial
statements);
- an increase in restricted cash related to our REMA operations;
- an increase in deposits in a collateral account related to an equipment
financing structure (please read Note 14(l) to our consolidated financial
statements);
- an increase in costs related to our Retail Energy business segments'
increased staffing levels and preparation for competition in the retail
electric market in Texas;
- reduced cash flows from our European Energy business segment primarily
resulting from a decline in electric power generation gross margins as
the Dutch electric market was completely opened to wholesale competition
on January 1, 2001; and
- other changes in working capital.
21
Net cash provided by operations in 2000 increased $240 million compared to
1999. This increase primarily resulted from:
- proceeds from the sale of an investment in marketable debt securities by
REPGB;
- improved operating results of our Wholesale Energy business segment's
California generating facilities;
- incremental cash flows provided by REPGB, acquired in the fourth quarter
of 1999;
- cash flows from REMA, acquired in the second quarter of 2000; and
- increased sales from our Electric Operations business segment due to
growth in usage and number of customers.
These increases were partially offset by increases in under-recovered fuel
costs of our Electric Operations business segment and Wholesale Energy's net
margin deposits on energy trading activities.
CASH USED IN INVESTING ACTIVITIES
Net cash used in investing activities decreased $1.2 billion during 2001
compared to 2000. This decrease was primarily due to no acquisitions being made
in 2001 as compared to the $2.1 billion acquisition of REMA in 2000, and the
funding of the remaining $982 million purchase obligation for REPGB in 2000.
These decreases were partially offset by additional capital expenditures in
2001 of $211 million primarily related to our Electric Operations business
segment, proceeds of $1.0 billion received in 2000 from the REMA sale-leaseback
and $642 million received in 2000 from the sale of our Latin America assets, net
of investments and advances.
Net cash used in investing activities increased $416 million during 2000
compared to 1999. This increase was primarily due to:
- the funding of the remaining purchase obligation for REPGB of $982
million on March 1, 2000;
- the acquisition of REMA for $2.1 billion on May 12, 2000; and
- increased capital expenditures related to the construction of domestic
power generation projects.
Proceeds of $1.0 billion from the REMA sale-leaseback in 2000, the sale of
a substantial portion of our Latin America investments in 2000 and the purchase
of $537 million of AOL Time Warner securities in 1999 partially offset these
increases.
CASH PROVIDED BY FINANCING ACTIVITIES
Cash flows provided by financing activities decreased $1.7 billion in 2001
compared to 2000, primarily due to a decline in short term borrowings partially
offset by $1.7 billion in net proceeds from the initial public offering of
Reliant Resources.
Cash flows provided by financing activities increased $209 million in 2000
compared to 1999, primarily due to an increase in short-term borrowings
partially offset by a decline in proceeds from long-term debt and the sale of
trust preferred securities.
22
FUTURE SOURCES AND USES OF CASH
The following table sets forth our consolidated capital requirements for
2001, and estimates of our consolidated capital requirements for 2002 through
2006 (in millions).
<Table>
<Caption>
2001 2002 2003 2004 2005 2006
------ ------ ------ ------ ------ ----
Electric Operations (with nuclear
fuel)(1)......................... $ 936 $ -- $ -- $ -- $ -- $ --
Electric Transmission and
Distribution(1).................. -- 338 320 381 362 352
Electric Generation (with nuclear
fuel)(1)......................... -- 285 192 89 79 45
Natural Gas Distribution........... 209 219 231 231 234 231
Pipelines and Gathering............ 54 76 45 45 43 38
Wholesale Energy(2)(3)............. 658 3,579 322 147 215 146
European Energy.................... 21 22 -- -- -- --
Retail Energy...................... 117 40 19 18 14 16
Other Operations................... 58 111 80 46 73 38
Major maintenance cash outlays..... 88 94 87 106 86 85
------ ------ ------ ------ ------ ----
Total............................ $2,141 $4,764 $1,296 $1,063 $1,106 $951
====== ====== ====== ====== ====== ====
</Table>
- ---------------
(1) Beginning in 2002, the Electric Operations business segment will be replaced
by the Electric Transmission and Distribution business segment and the
Electric Generation business segment. In December 2001, we formed Texas
Genco, LP, a Texas limited partnership, as an indirect, wholly owned
subsidiary (Texas Genco). It is anticipated that the majority interest in
Texas Genco held by CenterPoint Energy will be purchased by Reliant
Resources in early 2004 pursuant to the terms of an option that Reliant
Resources holds, or will otherwise be sold to one or more other parties. The
Texas generation operations referred to as our "Texas generation business"
throughout this Form 10-K will be reported as the "Electric Generation"
business segment beginning in 2002. Capital requirements for current
generation operations of Reliant Energy HL&P are included in the Electric
Generation business segment. Capital requirements for the remainder of
Reliant Energy HL&P's operations are included in the Electric Transmission
and Distribution business segment.
(2) Capital requirements for 2002 include $2.9 billion for the acquisition of
Orion Power by Reliant Resources.
(3) We currently estimate the capital expenditures by off-balance sheet special
purpose entities to be $704 million, $343 million, $163 million and $48
million in 2002, 2003, 2004 and 2005, respectively. Capital expenditures for
these projects have been excluded from the table above. Please read "Future
Sources and Uses -- Reliant Resources (unregulated businesses),"
"-- Off-Balance Sheet Transactions -- Construction Agency Agreements" and
"-- Equipment Financing Structure" below for additional information.
23
The following table sets forth estimates of our consolidated contractual
obligations as of December 31, 2001 to make future payments for 2002 through
2006 and thereafter (in millions):
<Table>
<Caption>
2007 AND
CONTRACTUAL OBLIGATIONS TOTAL 2002 2003 2004 2005 2006 THEREAFTER
- ----------------------- ------- ------ ------ ---- ------ ---- ----------
Long-term debt, including capital
leases(1)......................... $ 6,403 $ 538 $1,226 $ 90 $ 390 $218 $3,941
Short-term borrowing, including
credit facilities(1).............. 3,435 3,435 -- -- -- -- --
Trust preferred securities(2)....... 706 -- -- -- -- -- 706
REMA operating lease payments(3).... 1,560 136 77 84 75 64 1,124
Other operating lease payments(3)... 969 66 84 94 95 95 535
Trading and marketing
liabilities(4).................... 1,840 1,478 216 85 33 13 15
Non-trading derivative
liabilities(4).................... 1,121 472 198 115 62 35 239
Other commodity commitments(5)...... 4,014 451 314 340 344 348 2,217
Other long-term obligations......... 300 10 10 10 10 10 250
------- ------ ------ ---- ------ ---- ------
Total contractual cash
obligations.................... $20,348 $6,586 $2,125 $818 $1,009 $783 $9,027
======= ====== ====== ==== ====== ==== ======
</Table>
- ---------------
(1) For a discussion of short-term and long-term debt, please read Note 10 to
our consolidated financial statements.
(2) For a discussion of trust preferred securities, please read Note 11 to our
consolidated financial statements.
(3) For a discussion of REMA and other operating leases, please read Note 14(b)
to our consolidated financial statements.
(4) For a discussion of trading and marketing liabilities and non-trading
derivative liabilities, please read Note 5 to our consolidated financial
statements.
(5) For a discussion of other commodity commitments, please read Note 14(a) to
our consolidated financial statements. Excluded from the table above are
amounts to be acquired by Reliant Resources from Texas Genco under purchase
power and electric capacity commitments of $213 million and $57 million in
2002 and 2003, respectively.
The following discussion regarding future sources and uses of cash over the
next twelve months is presented separately for our regulated businesses and
unregulated businesses consistent with the separate liquidity plans that our
management has developed for CenterPoint Energy and Reliant Resources. We
believe that our borrowing capability combined with cash flows from operations
will be sufficient to meet the operational needs of our businesses for the next
twelve months.
RELIANT ENERGY (TO BECOME CENTERPOINT ENERGY SUBSEQUENT TO THE RESTRUCTURING)
Our liquidity and capital requirements will be affected by:
- capital expenditures;
- debt service requirements;
- the repayment of notes payable to Reliant Resources;
- the reduction in, and elimination of, programs under which we have sold
customer accounts receivable;
- proceeds from the expected initial public offering of Texas Genco;
- various regulatory actions; and
- working capital requirements.
24
We expect capital requirements to be met with cash flows from operations,
as well as proceeds from debt offerings and other borrowings. The following
table sets forth our capital requirements for 2001, and estimates of our capital
requirements for 2002 through 2006 (in millions):
<Table>
<Caption>
2001 2002 2003 2004 2005 2006
------ ---- ---- ---- ---- ----
Electric Operations (with nuclear
fuel)(1)............................... $ 936 $ -- $ -- $ -- $ -- $ --
Electric Transmission and
Distribution(1)........................ -- 338 320 381 362 352
Electric Generation (with nuclear
fuel)(1)............................... -- 285 192 89 79 45
Natural Gas Distribution................. 209 219 231 231 234 231
Pipelines and Gathering.................. 54 76 45 45 43 38
Other Operations......................... 14 36 34 15 41 5
------ ---- ---- ---- ---- ----
Total.................................. $1,213 $954 $822 $761 $759 $671
====== ==== ==== ==== ==== ====
</Table>
- ---------------
(1) Beginning in 2002, the Electric Operations business segment will be replaced
by the Electric Transmission and Distribution business segment and the
Electric Generation business segment. It is anticipated that the majority
interest in Texas Genco held by CenterPoint Energy will be purchased by
Reliant Resources in early 2004 pursuant to the terms of an option that
Reliant Resources holds, or will otherwise be sold to one or more other
parties. The Texas generation operations referred to as our "Texas
generation business" throughout this Form 10-K will be reported as the
"Electric Generation" business segment beginning in 2002. Capital
requirements for current generation operations of Reliant Energy HL&P are
included in the Electric Generation business segment. Capital requirements
for the remainder of Reliant Energy HL&P's operations are included in the
Electric Transmission and Distribution business segment.
The following table sets forth estimates of our contractual obligations to
make future payments for 2002 through 2006 and thereafter (in millions):
<Table>
<Caption>
2007 AND
CONTRACTUAL OBLIGATIONS TOTAL 2002 2003 2004 2005 2006 THEREAFTER
- ----------------------- ------- ------ ---- ---- ---- ---- ----------
Long-term debt, including capital
leases........................... $ 5,511 $ 514 $687 $ 48 $378 $206 $3,678
Short-term borrowing, including
credit facilities................ 3,138 3,138 -- -- -- -- --
Trust preferred securities......... 706 -- -- -- -- -- 706
Other operating lease
payments(1)...................... 110 14 12 7 6 5 66
Non-trading derivative
liabilities...................... 83 73 7 2 1 -- --
Other commodity commitments(2)..... 1,150 199 129 133 137 141 411
------- ------ ---- ---- ---- ---- ------
Total contractual cash
obligations................... $10,698 $3,938 $835 $190 $522 $352 $4,861
======= ====== ==== ==== ==== ==== ======
</Table>
- ---------------
(1) For a discussion of other operating leases, please read Note 14(b) to our
consolidated financial statements.
(2) For a discussion of other commodity commitments, please read Note 14(a) to
our consolidated financial statements.
Credit Facilities. As of December 31, 2001, we had credit facilities,
including facilities of Houston Industries FinanceCo LP (FinanceCo) and RERC
Corp., that provided for an aggregate of $5.4 billion in committed credit. As of
December 31, 2001, $3.1 billion was outstanding under these facilities including
$2.5 billion of commercial paper supported by the facilities, borrowings of $636
million and letters of credit of $2.5 million.
25
The following table summarizes amounts available under these credit
facilities at December 31, 2001 and commitments expiring in 2002 (in millions):
<Table>
<Caption>
AMOUNT OF
TOTAL UNUSED COMMITMENTS
COMMITTED AMOUNT AT EXPIRING
BORROWER TYPE OF FACILITY CREDIT 12/31/01 IN 2002
- -------- ---------------- --------- --------- -----------
Reliant Energy....................... Revolver $ 400 $ 236 $ 400
FinanceCo............................ Revolvers 4,300 1,671 4,300
RERC Corp. .......................... Revolver 350 347 --
RERC Corp. .......................... Receivables 350 4 350
------ ------ ------
Total........................... $5,400 $2,258 $5,050
====== ====== ======
</Table>
The RERC Corp. receivables facility was reduced from $350 million to $150
million in January 2002. Proceeds for the repayment of $196 million of advances
under the facility were obtained from the liquidation of a temporary investment
and the sale of commercial paper.
The revolving credit facilities contain various business and financial
covenants requiring us to, among other things, maintain leverage (as defined in
the credit facilities) below specified ratios. We are in compliance with the
covenants under all of these credit agreements. We do not expect these covenants
to materially limit our ability to borrow under these facilities. For additional
discussion, please read Note 10(a) to our consolidated financial statements.
The revolving credit facilities support commercial paper programs. The
maximum amount of outstanding commercial paper of an issuer is limited to the
amount of the issuer's aggregate revolving credit facilities less any direct
loans or letters of credit obtained under its revolvers. Due to an inability to
consistently satisfy all short-term borrowing needs by issuing commercial paper,
short-term borrowing needs have been met with a combination of commercial paper
and bank loans. The extent to which commercial paper will be issued in lieu of
bank loans will depend on market conditions and our credit ratings.
Pursuant to the terms of the existing agreements (but subject to certain
conditions precedent which we anticipate will be met) the revolving credit
agreements aggregating $4.3 billion of FinanceCo will terminate and CenterPoint
Energy revolving credit facilities of the same amount and with the same
termination dates will become effective on the date of Restructuring.
To the extent that we continue to need access to current amounts of
committed credit prior to the Distribution, we expect to extend or replace the
credit facilities on a timely basis. The terms of any new credit facilities are
expected to be adversely affected by the leverage of Reliant Energy, the amount
of bank capacity utilized by Reliant Energy, any delay in the date of
Restructuring and Distribution and conditions in the bank market. These same
factors are expected to make the syndication of new credit facilities more
difficult in the future. Proceeds from any issuance of debt in the capital
markets are expected to be used to retire a portion of our short-term debt and
reduce our need for committed revolving credit facilities.
26
Shelf Registrations. The following table lists shelf registration
statements existing at December 31, 2001 for securities expected to be sold in
public offerings.
<Table>
<Caption>
TERMINATING ON
DATE OF
REGISTRANT SECURITY AMOUNT(1) RESTRUCTURING
- ---------- -------- ------------ --------------
Reliant Energy.............. Preferred Stock $230 million Yes
Reliant Energy.............. Debt Securities 580 million Yes
Reliant Energy.............. Common Stock 398 million No
REI Trust II/Reliant Trust Preferred and related Junior 125 million Yes
Energy.................... Subordinated Debentures
RERC Corp................... Debt Securities 50 million No
</Table>
- ---------------
(1) The amount reflects the principal amount of debt securities, the aggregate
liquidation value of trust preferred securities and the estimated market
value of common stock based on the number of shares registered as of
December 31, 2001 and the closing market price of Reliant Energy common
stock on that date.
We expect to register $2.5 billion of debt securities some or all of which
may be issued either by Reliant Energy prior to the Restructuring or by
CenterPoint Energy after the Restructuring. Proceeds from the sale of these debt
securities are expected to be used to repay short-term borrowings. The amount
actually issued will depend on interest rates and other market conditions.
Debt Service Requirements. Excluding the repayments expected to be made on
the transition bonds described in Note 4(a) to our consolidated financial
statements, we have maturing long-term debt in 2002 aggregating $500 million.
Maturing debt is expected to be refinanced with new debt. In addition, Reliant
Energy has $175 million of 5.20% pollution control bonds that are expected to be
remarketed in 2002 as multi-year fixed-rate debt.
Debt service requirements will be affected by the overall level of interest
rates in 2002 and credit spreads applicable to the various issuers of debt in
2002. Up to $2.7 billion of long-term debt is expected to be issued or
remarketed in 2002 and we expect to have large amounts of short-term
floating-rate debt in 2002. At December 31, 2001, we had entered into five year
forward starting interest rate swaps having an aggregate notional amount of $500
million to hedge the interest rate on an anticipated 2002 offering of five year
notes. The weighted average rate on the swaps was 5.6%. At December 31, 2001, we
also had entered into interest rate swaps to fix the rate on $1.8 billion of our
floating rate debt. The weighted average rate on these swaps was 4.1% and the
swaps expire in 2002 and 2003. While we have, in some instances, hedged our
exposure to changes in interest rates by entering into interest rate swaps, the
swaps leave us exposed to changes in our credit spread relative to the market
indices reflected in the swaps.
Money Fund. We have a "money fund" through which Reliant Energy and
participating subsidiaries can borrow or invest on a short-term basis. Funding
needs are aggregated and external borrowing or investing is based on the net
cash position. The money fund's net funding requirements are generally met with
commercial paper and/or bank loans. At December 31, 2001, Reliant Resources had
$390 million invested in the money fund. Reliant Resources is expected to
withdraw its investment from the money fund on or before the Distribution. Funds
for repayment of the notes payable to Reliant Resources will be obtained from
bank loans or the issuance of commercial paper.
Environmental Issues. We anticipate investing up to $397 million in
capital and other special project expenditures between 2002 and 2006 for
environmental compliance. Of this amount, we anticipate expenditures to be
approximately $234 million and $132 million in 2002 and 2003, respectively.
These environmental compliance expenditures are included in the capital
requirements table presented above. For additional information related to
environmental issues, please read Note 14(f) to our consolidated financial
statements.
Initial Public Offering of Texas Genco. In 2002, approximately 20% of
Texas Genco is expected to be sold in an initial public offering or distributed
to holders of CenterPoint Energy common stock. The decision
27
whether to distribute the Texas Genco shares or to sell the shares in an initial
public offering will depend on numerous factors, including market conditions.
Proceeds, if any, are expected to be used to retire short-term debt.
Fuel Filing. As of December 31, 2000 and 2001, Reliant Energy HL&P was
under-collected on fuel recovery by $558 million and $200 million, respectively.
In two separate filings with the Texas Utility Commission in 2000, Reliant
Energy HL&P received approval to implement fuel surcharges to collect the
under-recovery of fuel expenses, as well as to adjust the fuel factor to
compensate for significant increases in the price of natural gas. Under the
Texas Electric Restructuring Law, a final settlement of these stranded costs
will occur in 2004.
Reliant Energy HL&P Rate Matters. The October 3, 2001 Order established
the transmission and distribution rates that became effective in January 2002.
The Texas Utility Commission determined that Reliant Energy HL&P had
overmitigated its stranded costs by redirecting transmission and distribution
depreciation and by accelerating depreciation of generation assets as provided
under the Transition Plan and Texas Electric Restructuring Law. In this final
order, Reliant Energy HL&P is required to reverse the amount of redirected
depreciation and accelerated depreciation taken for regulatory purposes as
allowed under the Transition Plan and the Texas Electric Restructuring Law. Per
the October 3, 2001 Order, our Electric Operations business segment recorded a
regulatory liability to reflect the prospective refund of the accelerated
depreciation. Our Electric Operations business segment began refunding excess
mitigation credits with the January 2002 unbundled bills, to be refunded over a
seven year period. The annual cash flow impact of the reversal of both
redirected and accelerated depreciation is a decrease of approximately $225
million. Under the Texas Electric Restructuring Law, a final settlement of these
stranded costs will occur in 2004. For further discussion, please read Note 4(a)
to our consolidated financial statements.
In addition to the above factors, our liquidity and capital requirements
could be affected by:
- a downgrade in credit ratings;
- the need to provide cash collateral in connection with trading
activities;
- various regulatory actions; and
- funding of our pension plan.
Impact on Liquidity of a Downgrade in Credit Ratings. At December 31,
2001, Moody's Investors Service, Inc. (Moody's), Standard & Poor's, a division
of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned the
following credit ratings to senior debt of Reliant Energy and certain
subsidiaries:
<Table>
<Caption>
MOODY'S S&P
----------------- -----------------
COMPANY/INSTRUMENT RATING OUTLOOK RATING OUTLOOK RATING FITCH WATCH OUTLOOK
- ------------------ ------ --------- ------ --------- ------ ----------- ---------
Reliant Energy
Senior Secured Debt....... A3 Stable(1) BBB+ Stable(2) A- Negative(3) N/A
Senior Unsecured Debt..... Baa1 Stable(1) BBB Stable(2) BBB+ Negative(3) N/A
Reliant Energy FinanceCo II
LP
Senior Debt............... Baa1 Stable(1) BBB Stable(2) BBB N/A Stable(4)
RERC Corp.
Senior Debt............... Baa2 Stable(1) BBB+ Stable(2) BBB+ Negative(3) N/A
</Table>
- ---------------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) A "stable" outlook from S&P indicates that the rating is not likely to
change over the intermediate to longer term.
(3) A "negative" watch from Fitch signals that the rating may be downgraded or
affirmed in the near term. Fitch has indicated that the Reliant Energy
senior secured debt ratings will change from A- to BBB+
28
upon the distribution of Reliant Resources shares and that the RERC Corp.
senior debt ratings will change from BBB+ to BBB upon the distribution of
Reliant Resources shares.
(4) A "stable" outlook from Fitch signals that the medium term view of the
credit trend of an issuer is stable rather than positive or negative.
We cannot assure you that these ratings will remain in effect for any given
period of time or that one or more of these ratings will not be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities and may be revised or
withdrawn at any time by the rating agency. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to access capital on acceptable terms.
A decline in credit ratings would increase commitment fees and borrowing
costs under our existing bank credit facilities. A decline in credit ratings
would also adversely affect our ability to issue commercial paper and the
interest rates applicable to commercial paper. Increased direct borrowings under
our bank credit facilities could also result in the payment of usage fees under
the terms of these arrangements. A decline in credit ratings would also increase
the interest rate on long-term debt to be issued in the capital markets.
Our revolving credit agreements are broadly syndicated committed facilities
which contain "material adverse change" clauses that could impact our ability to
borrow under these facilities. The "material adverse change" clauses generally
relate to our ability to perform our obligations under the agreements.
The $150 million receivables facility of RERC Corp. requires the
maintenance of credit ratings of at least BB from S&P and Ba2 from Moody's.
Advances under the facility would need to be repaid in the event a credit rating
fell below the threshold.
As previously discussed, bank facilities of FinanceCo are expected to be
converted into bank facilities of CenterPoint Energy on the date of
Restructuring. There is a ratings-related condition precedent to the conversion
from the existing FinanceCo bank credit facilities (totaling $4.3 billion) to
facilities under which CenterPoint Energy will become the obligor. The condition
precedent requires that CenterPoint Energy be rated at least BBB by S&P and Baa2
by Moody's at the time of Restructuring. We believe that we could obtain a
waiver of this condition, if necessary. However, if we were unable to obtain
such a waiver, the facilities would remain obligations of FinanceCo until the
earlier of 90 days after the date of Restructuring or the expiration of the
facilities in July 2002, subject to compliance with applicable covenants.
Similar ratings-related provisions govern the transfer to CenterPoint
Energy of rights and obligations under certain interest rate swap agreements
entered into by Reliant Energy and Houston Industries FinanceCo LP to effect
interest rate hedging. Interest rate swaps having an aggregate notional amount
of $1.5 billion as of December 31, 2001 contained such provisions. These
agreements are generally assumable by CenterPoint Energy without the consent of
the counterparties, provided that CenterPoint Energy's rating is at least BBB-
from S&P or Baa3 from Moody's. We believe that we could obtain the consent of
the counterparties if necessary, but if we were unable to do so, the swaps would
remain obligations of the current counterparties until their expiration. All of
the swaps terminate no later than 2004.
As discussed in Note 8 to our consolidated financial statements, each ZENS
note is exchangeable at the holder's option at any time for an amount of cash
equal to 95% of the market value of the reference shares of AOL TW common stock
attributable to each ZENS note. If our credit worthiness were to drop such that
ZENS note holders felt our liquidity was adversely affected or the market for
the ZENS notes was to become illiquid, some ZENS holders might decide to
exchange their ZENS for cash. Funds for the payment of cash upon exchange could
be obtained from the sale of the AOL TW common stock that we own or from other
sources. We own shares of AOL TW common stock equal to 100% of the "reference
shares" used to calculate our obligation to the holders of the ZENS notes.
Certain of the contracts that we have entered into on behalf of Texas Genco
for the sale of capacity from our Texas generation business contain requirements
obligating us to put up additional security in the event that our rating or the
rating of CenterPoint Energy falls below BBB- from S&P or Baa3 from Moody's.
These
29
requirements stem from reciprocal provisions under power purchase and sale
agreements with purchasers of capacity to be delivered in various monthly,
12-month or 24-month periods or "strips" until December 2003. If a downgrade
below either of these levels were to occur, the purchasers would be entitled to
call upon us to provide collateral to secure our obligations in a "commercially
reasonable" amount within three business days of notice. Failure to provide this
collateral entitles the other party to terminate the agreement and unwind all
pending transactions under the agreement. Our Texas generation business is
always the seller under these agreements, and its performance obligation in all
cases is one of delivery, rather than payment. Accordingly, it is difficult to
quantify the amount of collateral we would be required to provide as assurance
for these delivery obligations. We believe that any such quantification should
be predicated on our Texas generation business' ultimate exposure under these
agreements. Our Texas generation business has no exposure until (1) it cannot
deliver power as called for in the agreements and (2) the market cost of
replacement power has increased above the contract price. In the unlikely event
that our Texas generation business could not deliver any of this power as
agreed, we estimate that our Texas generation business' total exposure under
these contracts at December 31, 2001 was approximately $73 million.
As part of its normal business operations, our Texas generation business
has also entered power purchase and sale agreements with counterparties that
contain similar provisions that require a party to provide additional collateral
on three business days notice when that party's rating falls below BBB- from S&P
or Baa3 from Moody's. Our Texas generation business both buys and sells under
these agreements, and we use them whenever possible either to locate less
expensive power than our Texas generation business' marginal cost of generation
or to sell power to another party who is willing to pay more than our marginal
cost of generation. Our Texas generation business' purchases for 2001 under
agreements with ratings triggers were approximately $23 million and its sales
under those agreements were approximately $8 million. This compares to total
purchases of approximately $125 million and total sales of approximately $32
million under all buy/sell agreements in 2001. We believe that this risk is
mitigated because most of the purchases and sales under these arrangements take
place over relatively short time periods; typically, these transactions are for
one-day deliveries and rarely exceed periods of one month.
Entex Gas Resources Corp., a wholly owned subsidiary of RERC Corp.,
provides comprehensive natural gas sales and services to industrial and
commercial customers who are primarily located within or near the territories
served by our pipelines and distribution subsidiaries. In order to hedge its
exposure to natural gas prices, Entex Gas Resources Corp. will have agreements
with provisions standard to the industry that establish credit thresholds and
then require a party to provide additional collateral on two business days'
notice when that party's rating or the rating of a credit support provider for
that party (RERC Corp. in this case), falls below those levels. The senior
unsecured debt of RERC Corp. is currently rated BBB+ by S&P and Baa2 by Moody's.
Based on these ratings, we estimate that unsecured credit limits extended to
Entex Gas Resources Corp. by counterparties could aggregate $250 million;
however, utilized credit capacity would typically be lower.
Regulatory Matters. Our liquidity can be impacted by regulatory actions
affecting our Electric Operations and our Natural Gas Distribution business
segments. For further discussion, please read Note 4 to our consolidated
financial statements.
Treasury Stock Purchases. As of December 31, 2001, we were authorized
under our common stock repurchase program to purchase an additional $271 million
of our common stock. Our purchases under our repurchase program depend on market
conditions, might not be announced in advance and may be made in open market or
privately negotiated transactions. CenterPoint Energy has no current plans to
engage in a significant stock buy-back program, but may seek to repurchase
shares in the open market for use in various benefit and employee compensation
plans, or to maintain a targeted balance of outstanding shares to the extent
that original issue stock is used for such purposes.
Pension and Postretirement Benefits Funding. We make contributions to
achieve adequate funding of Company sponsored pension and postretirement
benefits in accordance with applicable regulations and rate orders. Based on
current estimates, we expect to have funding requirements, excluding Reliant
Resources, of
30
approximately $330 million for the period 2002-2006. These anticipated funding
requirements are not reflected in the table of contractual obligations presented
above.
RELIANT RESOURCES -- UNREGULATED BUSINESSES
Liquidity and capital requirements for these businesses are affected
primarily by the results of operations, capital expenditures, debt service
requirements and working capital needs. Reliant Resources expects to grow these
businesses through the construction of new generation facilities and the
acquisition of generation facilities, the expansion of their energy trading and
marketing activities and the expansion of their energy retail business. Reliant
Resources expects any resulting capital requirements to be met with cash flows
from operations, and proceeds from debt and equity offerings, project
financings, securitization of assets, other borrowings and off-balance sheet
financings. Additional capital expenditures, some of which may be substantial,
depend to a large extent upon the nature and extent of future project
commitments which are discretionary. In the discussion below, Reliant Resources
has provided several tables outlining their expected future capital requirements
by category of expenditure followed by more detailed descriptions of the most
significant of their currently known future capital requirements and
descriptions of known uncertainties that could impact these items.
The following table sets forth Reliant Resources' consolidated capital
requirements for 2001, and estimates of their consolidated capital requirements
for 2002 through 2006 (in millions).
<Table>
<Caption>
2001 2002 2003 2004 2005 2006
---- ------ ---- ---- ---- ----
Wholesale Energy(1)(2)(3)................ $658 $3,579 $322 $147 $215 $146
European Energy.......................... 21 22 -- -- -- --
Retail Energy............................ 117 40 19 18 14 16
Other Operations......................... 44 75 46 31 32 33
Major maintenance cash outlays........... 88 94 87 106 86 85
---- ------ ---- ---- ---- ----
Total.................................. $928 $3,810 $474 $302 $347 $280
==== ====== ==== ==== ==== ====
</Table>
- ---------------
(1) Capital requirements for 2002 includes $2.9 billion for the acquisition of
Orion Power.
(2) In connection with Reliant Resources' separation from Reliant Energy,
Reliant Energy has granted Reliant Resources an option, subject to
completion of the Distribution, to purchase the majority interest in Texas
Genco held by CenterPoint Energy in January 2004. This option may be
exercised between January 10, 2004 and January 24, 2004. The purchase of
Texas Genco has been excluded from the above table. For additional
information regarding this option to purchase Texas Genco, please read Note
4(b) to our consolidated financial statements.
(3) Reliant Resources currently estimates the capital expenditures by
off-balance sheet special purpose entities to be $704 million, $343 million,
$163 million and $48 million in 2002, 2003, 2004 and 2005, respectively.
Capital expenditures for these projects have been excluded from the table
above. Please read "Future Sources and Uses -- Reliant
Resources -- unregulated businesses," "-- Off-Balance Sheet
Transactions -- Construction Agency Agreements" and "-- Equipment Financing
Structure" below for additional information.
Acquisition of Orion Power. On February 19, 2002, Reliant Resources
acquired all of the outstanding shares of common stock of Orion Power for $26.80
per share in cash for an aggregate purchase price of $2.9 billion. As of
February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of cash acquired, some of which is restricted pursuant to debt
covenants). Reliant Resources funded the purchase of Orion Power with a $2.9
billion credit facility (Orion Bridge Facility) and $41 million of cash on hand.
Please read "-- Consolidated Sources of Cash -- Orion Bridge Facility" for
further information.
Generating Projects. As of December 31, 2001, Reliant Resources had three
generating facilities under construction. Total estimated costs of constructing
these facilities are $1.1 billion, including $304 million in commitments for the
purchase of combustion turbines. As of December 31, 2001, Reliant Resources had
31
incurred $690 million of the total projected costs of these projects, which were
funded primarily from equity and debt facilities. In addition, Reliant Resources
has options to purchase additional combustion turbines for a total estimated
cost of $42 million, but is actively attempting to market these turbines, having
determined that they are in excess of their current needs. In addition to these
facilities, Reliant Resources is constructing facilities as construction agents
under the construction agency agreements under synthetic leasing arrangements,
which permit them to lease or buy each of these facilities at the conclusion of
their construction. For more information regarding the construction agency
agreements, please read "-- Off Balance Sheet Transactions -- Construction
Agency Agreements."
Environmental Expenditures. Reliant Resources anticipates investing up to
$135 million in capital and other special project expenditures between 2002 and
2006 for environmental compliance, totaling approximately $53 million, $20
million, $9 million, $29 million and $24 million in 2002, 2003, 2004, 2005 and
2006, respectively, which is included in the above table. Additionally,
environmental capital expenditures for the recently acquired Orion Power assets
were estimated by Orion Power to be approximately $241 million over the same
time period. Reliant Resources is currently reviewing Orion Power's estimates.
The following table sets forth estimates of Reliant Resources' consolidated
contractual obligations as of December 31, 2001 to make future payments for 2002
through 2006 and thereafter (in millions):
<Table>
<Caption>
2007 AND
CONTRACTUAL OBLIGATIONS TOTAL 2002 2003 2004 2005 2006 THEREAFTER
- ----------------------- ------ ------ ------ ---- ---- ---- ----------
Long-term debt..................... $ 892 $ 24 $ 539 $ 42 $ 12 $ 12 $ 263
Short-term borrowing, including
credit facilities................ 297 297 -- -- -- -- --
Mid-Atlantic generating assets
operating lease payments......... 1,560 136 77 84 75 64 1,124
Other operating lease payments..... 859 52 72 87 89 90 469
Trading and marketing
liabilities...................... 1,840 1,478 216 85 33 13 15
Non-trading derivative
liabilities...................... 1,038 399 191 113 61 35 239
Other commodity commitments........ 3,134 465 242 207 207 207 1,806
Other long-term obligations........ 300 10 10 10 10 10 250
------ ------ ------ ---- ---- ---- ------
Total contractual cash
obligations................... $9,920 $2,861 $1,347 $628 $487 $431 $4,166
====== ====== ====== ==== ==== ==== ======
</Table>
Long-term debt obligations as of December 31, 2001, include $829 million of
borrowings under credit facilities that have been classified as long-term debt,
based upon the availability of committed credit facilities and management's
intention to maintain these borrowings in excess of one year.
As of December 31, 2001, Reliant Resources has issued $396 million of
letters of credit, of which $345 million were issued under two credit facilities
expiring in 2003 and $51 million were issued under a credit facility expiring in
2004.
Mid-Atlantic Assets Lease Obligation. In August 2000, Reliant Resources'
subsidiaries entered into separate sale-leaseback transactions with each of the
three owner-lessors for their respective 16.45%, 16.67% and 100% interests in
the Conemaugh, Keystone and Shawville generating stations, respectively, which
Reliant Resources acquired as part of the REMA acquisition. These lessees lease
an interest in each facility from each owner-lessor under a facility lease
agreement. The equity interests in all the subsidiaries of REMA are pledged as
collateral for REMA's lease obligations. In addition, the subsidiaries have
guaranteed the lease obligations. The lease documents contain restrictive
covenants that restrict REMA's ability to, among other things, make dividend
distributions unless REMA satisfies various conditions. The covenant restricting
dividends would be suspended if the direct or indirect parent of REMA, meeting
specified criteria, including having a credit rating on its long-term unsecured
senior debt of at least BBB from Standard & Poor's and Baa2 from Moody's,
guarantees the lease obligations. For additional discussion of these lease
transactions, please read Notes 3(a) and 14(b) to our consolidated financial
statements. Reliant Resources expects to make lease
32
payments through 2029 under these leases, with total cash payments of $1.6
billion. The lease terms expire in 2034. During 2000 and 2001, cash lease
payments totalled $1 million and $259 million, respectively.
Other Operating Lease Commitments. For a discussion of other operating
leases, please read Note 14(b) to our consolidated financial statements.
Other Commodity Commitments. For a discussion of other commodity
commitments, please read Note 14(a) to our consolidated financial statements.
Naming Rights to Houston Sports Complex. In October 2000, Reliant
Resources acquired the naming rights for the new football stadium for the
Houston Texans, the National Football League's thirty-second franchise. The
agreement extends for 31 years. The aggregate undiscounted cost of the naming
rights under this agreement is expected to be $300 million. Starting in 2002,
when the new stadium is operational, Reliant Resources will pay $10 million each
year through 2032 for annual advertising under this agreement. For additional
information on the naming rights agreement, please read Note 14(d) to our
consolidated financial statements.
Payment to Reliant Energy. To the extent that Reliant Resources' price for
providing retail electric service to residential and small commercial customers
in Reliant Energy HL&P's historical service territory during 2002 and 2003,
which price is mandated by the Texas Electric Restructuring Law, exceeds the
market price of electricity, Reliant Resources will be required to make a
payment to Reliant Energy in early 2004. Due to the nature of this possible
payment, Reliant Resources currently cannot reasonably estimate this payment,
and accordingly, it is excluded from the above tables.
Treasury Stock Purchases. On December 6, 2001, the Reliant Resources'
board of directors authorized the purchase of up to 10 million additional shares
of common stock through June 2003. Purchases will be made on a discretionary
basis in the open market or otherwise at times and in amounts as determined by
management subject to market conditions, legal requirements and other factors.
Since the date of such authorization through March 28, 2002, Reliant Resources
has not purchased any of these shares of their common stock under this program.
In addition to the capital requirements discussed above, the following
items, among others, could impact future capital requirements for Reliant
Resources.
Downgrade in Credit Rating. In accordance with industry practice, Reliant
Resources has entered into commercial contracts or issued guarantees related to
their trading, marketing and risk management operations that require them to
maintain an investment grade credit rating. If one or more of their credit
ratings decline below investment grade, Reliant Resources may be obligated to
provide additional or other credit support to the guaranteed parties in the form
of a pledge of cash collateral, a letter of credit or other similar credit
support.
Counterparty Credit Risk. Reliant Resources is exposed to the risk that
counterparties who owe them money or physical commodities, such as energy or
gas, as a result of market transactions fail to perform their obligations.
Should the counterparties to these arrangements fail to perform, Reliant
Resources might incur losses if they are forced to acquire alternative hedging
arrangements or replace the underlying commitment at then-current market prices.
In addition, Reliant Resources might incur additional losses to the extent of
amounts, if any, already paid to the defaulting counterparties.
CONSOLIDATED SOURCES OF CASH
Reliant Resources believes that their current level of cash and borrowing
capability, along with their future anticipated cash flows from operations and
assuming successful refinancings of credit facilities as they mature, will be
sufficient to meet the existing operational needs of their business for the next
12 months. If cash generated from operations is insufficient to satisfy their
liquidity requirements, Reliant Resources may seek to sell either equity or debt
securities or obtain additional credit facilities or long-term financings from
financial institutions. In the discussion below, Reliant Resources has provided
a description of the significant
33
factors that could impact their cash flows from operations, their currently
available liquidity sources, currently contemplated future liquidity sources and
known uncertainties that could impact these sources.
The following items will affect Reliant Resources' future cash flows from
operations:
Reliant Resources Restricted Cash. Covenants under the Mid-Atlantic assets
lease, discussed above, restrict REMA's ability to make dividend distributions.
The restricted cash is available for REMA's working capital needs and for it to
make future lease payments. As of December 31, 2001, REMA had $167 million of
restricted cash. Reliant Resources currently anticipates that REMA will be able
to satisfy the conditions necessary to distribute these restricted funds in
2002. In addition, the terms of two of their subsidiaries' indebtedness restrict
the subsidiaries' ability to pay dividends or make restricted payments to
Reliant Resources in some circumstances. Specifically, their subsidiary which
holds an electric power generation facility in Channelview, Texas (Channelview)
and their subsidiary which holds an equity investment in the entity owning and
operating an electric power generation facility in Nevada (El Dorado) are each
party to credit agreements used to finance construction of these generating
plants. Both the Channelview credit agreement and the El Dorado credit agreement
allow the respective subsidiary to pay dividends or make restricted payments
only if specified conditions are satisfied, including maintaining specified debt
service coverage ratios and debt service reserve account balances. In both
cases, the amount of the dividends or restricted payments that may be paid if
the conditions are met is limited to a specified level and may be paid only from
a particular account.
Orion Power Restricted Cash. Substantially all of Orion Power's operations
are conducted by its subsidiaries. The terms of some of its subsidiaries'
indebtedness restrict the subsidiaries' ability to pay dividends to Orion Power
or Reliant Resources. Restricted funds are available for such subsidiaries to
make debt service payments and to meet their working capital needs. In addition,
covenants under some indebtedness of Orion Power restrict its ability to pay
dividends to Reliant Resources unless Orion Power meets certain conditions,
including the ability to incur additional indebtedness without violating the
required fixed charge coverage ratio of 2.0 to 1.0. A credit facility of Orion
Power also restricts its ability to pay dividends to Reliant Resources unless
the restrictions contained in certain of its subsidiaries' credit agreements
have terminated and no restrictions remain under its credit agreements.
California Trade Receivables. As of December 31, 2001, Reliant Resources
was owed $302 million by Cal ISO, the California Power Exchange (Cal PX) and the
California Department of Water Resources (CDWR) and California Energy Resource
Scheduling for energy sales in the California wholesale market, during the
fourth quarter of 2000 through December 31, 2001 and has recorded an allowance
against such receivables of $68 million. From January 1, 2002 through March 26,
2002, Reliant Resources has collected $45 million of these receivable balances.
For additional information regarding uncertainties in the California wholesale
market, please read Notes 14(f) and 14(g) to our consolidated financial
statements.
Other Items. For other items that may affect our future cash flows from
operations, please read "-- Certain Factors Affecting Our Future Earnings"
related to the Reliant Resources business segments.
The following discussion summarizes Reliant Resources' currently available
liquidity sources and material factors that could impact that availability.
Credit Facilities. The following table provides a summary of the amounts
owed and amounts available under Reliant Resources' various credit facilities
(in millions).
<Table>
<Caption>
TOTAL EXPIRING BY
COMMITTED DRAWN LETTERS UNUSED DECEMBER 31,
CREDIT AMOUNT OF CREDIT AMOUNT 2002(1)
--------- ------ --------- ------ ------------
Reliant Resources, as of December 31,
2001.................................. $5,563 $1,078 $396 $4,089 $1,114
Orion Power, as of February 19, 2002.... 2,028 1,827 95 106 1,736
------
Total................................. $2,850
======
</Table>
34
- ---------------
(1) Excludes $383 million of facilities expiring in November 2002 as borrowings
under such facilities are convertible into a long-term loan.
As of February 19, 2002, Reliant Resources has $2.9 billion of credit
facilities which will expire in 2002. To the extent that they continue to need
access to this amount of committed credit, Reliant Resources expects to extend
or replace these facilities. The current credit environment currently impacting
their industry may require their future facilities to include terms that are
more restrictive or burdensome or at higher borrowing rates than those of their
current facilities.
Reliant Resources Credit Facilities Covenants. As of December 31, 2001,
Reliant Resources, including certain of their subsidiaries, had committed credit
facilities of $5.6 billion. Of these facilities, $5.0 billion contain various
business and financial covenants requiring them to, among other things, maintain
a ratio of net balance sheet debt to the sum of net balance sheet debt,
subordinated affiliate balance sheet debt and stockholders' equity not to exceed
0.60 to 1.00. These covenants are not anticipated to materially restrict Reliant
Resources from borrowing funds or obtaining letters of credit under these
facilities. The remaining credit facilities of $0.6 billion, which were held by
certain of their domestic power generation subsidiaries, contain various
business and financial covenants that are typical for limited or non-recourse
project financings. Such covenants include restrictions on dividends and capital
expenditures, as well as requirements regarding insurance, approval of operating
budgets and commercial contracts. These covenants are not anticipated to
materially restrict Reliant Resources from borrowing funds or obtaining letters
of credit under their credit facilities. None of the above committed bank credit
facilities have any defaults or prepayments triggered by changes in credit
ratings, or are in any way linked to the price of Reliant Resources' common
stock or any other traded instrument.
For additional information regarding the terms and related interest rates
of these credit facilities, please read Note 10 of our consolidated financial
statements.
Orion Power Credit Facilities. The credit facilities of Orion Power and
its subsidiaries contain various business and financial covenants that are
typical for limited or non-recourse project financings. Such covenants include
restrictions on dividends and capital expenditures, as well as requirements
regarding insurance, approval of operating budgets and commercial contracts.
These include covenants that require two of Orion Power's significant
subsidiaries which have credit facilities with outstanding borrowings of $1.6
billion as of December 31, 2001, to, among other things, maintain a debt service
coverage ratio of at least 1.5 to 1.0, and for Orion Power, which has a $75
million credit facility, to, among other things, maintain a debt service
coverage ratio of at least 1.4 to 1.0. One of the subsidiaries may not be able
to meet this debt service coverage ratio for the quarter ended June 30, 2002,
and Orion Power did not meet the debt service coverage ratio for the quarter
ended March 31, 2002. In the event that Orion Power is unable to meet this
financial covenant for a second consecutive fiscal quarter, it would constitute
a default under its credit facility. Reliant Resources currently intends to
arrange for the repayment, refinancing or amendment of these facilities prior to
June 30, 2002. If these facilities are not repaid, refinanced or amended prior
to that date, and if a waiver is required under either or both of these credit
facilities, Reliant Resources believes that they will be able to obtain such a
waiver on or prior to June 30, 2002. Reliant Resources currently has no
assurance that they will be able to obtain such a waiver or amendment from the
respective lender groups if required under either or both of these credit
facilities.
Orion Bridge Facility. In November 2001, Reliant Resources entered into a
$2.2 billion term loan facility to be utilized for the acquisition of Orion
Power. In January 2002, the facility was increased to $2.9 billion. On February
19, 2002, in connection with the Orion Power acquisition Reliant Resources
borrowed $2.9 billion under the Orion Bridge Facility, which is required to be
repaid on or before February 19, 2003.
Potential Future Liquidity Sources. Reliant Resources is currently
considering pursuing the following sources of cash to meet their future capital
requirements.
Commercial Paper Program. Reliant Resources plans to commence a commercial
paper program in 2002, which will be supported by their existing credit
facilities. Although they have not yet determined the size
35
of such program, Reliant Resources does not expect that it would exceed $300
million initially, due to market conditions and their current credit ratings. To
the extent that they are not successful in placing commercial paper
consistently, Reliant Resources will borrow directly under their existing credit
facilities.
Debt Securities in the Capital Markets. As part of refinancing the Orion
Bridge Facility, Reliant Resources currently expects that they will issue
various fixed and floating rate debt securities in 2002 having maturities up to
ten years or greater depending upon market conditions. Reliant Resources expects
to offer debt securities in the amount of $2.5 to $3.0 billion, depending on
market conditions. Their ability to complete such debt offerings in the capital
markets will depend on their future performance and prevailing market
conditions. This Form 10-K does not constitute an offer to sell or the
solicitation of an offer to buy debt securities of Reliant Resources or their
subsidiaries.
Settlement of Indemnification of REPGB Stranded Costs. In December 2001,
REPGB and its former shareholders entered into a settlement agreement resolving
the former shareholders' stranded cost indemnity obligations under the purchase
agreement of REPGB. Under the settlement agreement, the former shareholders paid
to REPGB NLG 500 million ($202 million based on an exchange rate of 2.48 NLG per
U.S. dollar as of December 31, 2001) in January and February 2002. In addition,
under the settlement agreement, the former shareholders waived all rights under
the original indemnification agreement to claim distributions from NEA, a 22.5%
owned equity investment. Reliant Resources estimates that there will be future
distributions from 2002 through 2005 from NEA to REPGB totaling approximately
$299 million. For additional information regarding the settlement agreement,
Reliant Resources' investment in NEA and indemnification of district heat
contract obligations, please read Note 14(h) to our consolidated financial
statements.
Factors Affecting Our Sources of Cash and Liquidity. As a result of
several recent events, including the United States economic recession, the price
decline of the common stock of participants in Reliant Resources' industry
sector and the downgrading of the credit ratings of several of Reliant
Resources' significant competitors, the availability and cost of capital for
their business and the businesses of their competitors have been adversely
affected. Any future acquisition or development projects will likely require
Reliant Resources to access substantial amounts of capital from outside sources
on acceptable terms. Reliant Resources may also need external financing to fund
capital expenditures, including capital expenditures necessary to comply with
air emission regulations or other regulatory requirements. If Reliant Resources
is are unable to obtain outside financing to meet their future capital
requirements on terms that are acceptable to them, their financial condition and
future results of operations could be materially adversely affected. In order to
meet their future capital requirements, Reliant Resources may increase the
proportion of debt in their overall capital structure. Increases in their debt
levels may adversely affect their credit ratings thereby increasing the cost of
their debt. In addition, the capital constraints currently impacting their
industry may require Reliant Resources' future indebtedness to include terms
and/or pricing that are more restrictive or burdensome than those of their
current indebtedness. This may negatively impact their ability to operate their
business, or severely restrict or prohibit distributions from their
subsidiaries.
Reliant Resources' ability to arrange financing, including refinancing, and
their cost of capital are dependent on the following factors:
- general economic and capital market conditions;
- maintenance of acceptable credit ratings;
- credit availability from banks and other financial institutions;
- investor confidence in Reliant Resources, their competitors and peer
companies and their wholesale power markets;
- market expectations regarding their future earnings and probable cash
flows;
- market perceptions of Reliant Resources' ability to access capital
markets on reasonable terms;
- the success of current power generation projects;
- the perceived quality of new power generation projects; and
- provisions of relevant tax and securities laws.
36
Credit Ratings. Credit ratings for Reliant Resources' senior unsecured
debt are as follows:
<Table>
<Caption>
DATE ASSIGNED RATING AGENCY RATING OUTLOOK
- ------------- ------------- ------ --------
March 22, 2002.................................. Moody's Baa3 Stable
February 14, 2002............................... Fitch(1) BBB Negative
March 21, 2002.................................. Standard & Poor's BBB Stable
</Table>
- ---------------
(1) Fitch assigned a negative rating outlook to reflect its analysis of Reliant
Resources' plan for financing and integrating the acquisition of Orion
Power.
Reliant Resources cannot assure you that these ratings will remain in
effect for any given period of time or that one or more of these ratings will
not be lowered or withdrawn entirely by a rating agency. Reliant Resources notes
that these credit ratings are not recommendations to buy, sell or hold Reliant
Resources' securities and may be revised or withdrawn at any time by a rating
agency. Each rating should be evaluated independently of any other rating. Any
future reduction or withdrawal of one or more of their credit ratings could have
a material adverse impact on Reliant Resources' ability to access capital on
acceptable terms. Reliant Resources has commercial contracts and/or guarantees
related to their trading, marketing and risk management and hedging operations
that require them to maintain an investment grade credit rating. If their credit
rating declines below investment grade, Reliant Resources estimates that they
could be obligated to provide significant credit support to the counterparties
in the form of a pledge of cash collateral, a letter of credit or other similar
credit support.
Furthermore, if their credit ratings decline below an investment grade
credit rating, Reliant Resources' trading partners may refuse to trade with them
or trade only on terms less favorable to them. As of December 31, 2001, Reliant
Resources had $214 million of margin deposits on energy trading and hedging
activities posted as collateral with counterparties. As of December 31, 2001,
Reliant Resources had $1.5 billion available under their credit facilities to
satisfy future commodity obligations.
OFF-BALANCE SHEET TRANSACTIONS
Construction Agency Agreements. In 2001, Reliant Resources, through
several of their subsidiaries, entered into operative documents with special
purpose entities to facilitate the development, construction, financing and
leasing of several power generation projects. The special purpose entities are
not consolidated by Reliant Resources. The special purpose entities have an
aggregate financing commitment from equity and debt participants (Investors) of
$2.5 billion of which the last $1.1 billion is currently available only if the
cash is collateralized. The availability of the commitment is subject to
satisfaction of various conditions, including the obligation to provide cash
collateral for the loans and letters of credit outstanding on November 27, 2004.
Reliant Resources, through several of their subsidiaries, acts as construction
agent for the special purpose entities and is responsible for completing
construction of these projects by December 31, 2004, but Reliant Resources has
generally limited their risk during construction to an amount not in excess of
89.9% of costs incurred to date, except in certain events. Upon completion of an
individual project and exercise of the lease option, their subsidiaries will be
required to make lease payments in an amount sufficient to provide a return to
the Investors. If Reliant Resources does not exercise their option to lease any
project upon its completion, they must purchase the project or remarket the
project on behalf of the special purpose entities. Reliant Resources' ability to
exercise the lease option is subject to certain conditions. Reliant Resources
must guarantee that the Investors will receive an amount at least equal to 89.9%
of their investment in the case of a remarketing sale at the end of
construction. At the end of an individual project's initial operating lease term
(approximately five years from construction completion), Reliant Resources'
subsidiary lessees have the option to extend the lease with the approval of
Investors, purchase the project at a fixed amount equal to the original
construction cost, or act as a remarketing agent and sell the project to an
independent third party. If the lessees elect the remarketing option, they may
be required to make a payment of an amount not to exceed 85% of the project
cost, if the proceeds from remarketing are not sufficient to repay the
Investors. Reliant Resources has guaranteed the performance and payment of their
subsidiaries' obligations during the construction periods and, if the lease
option is exercised, each lessee's obligations during the lease period. At
anytime during the
37
construction period or during the lease, Reliant Resources may purchase a
facility by paying an amount approximately equal to the outstanding balance plus
costs. As of December 31, 2001, the special purpose entities had property, plant
and equipment of $428 million and net other assets of $52 million, which were
primarily restricted cash and debt obligations of $465 million. As of December
31, 2001, the special purpose entities had equity from unaffiliated third
parties of $15 million. Reliant Resources currently estimates the aggregate cost
of the three generating facilities that are currently under construction by the
special purpose entities to be approximately $1.8 billion.
Equipment Financing Structure. Reliant Resources, through their
subsidiary, REPG, has entered into an agreement with a bank whereby the bank, as
owner, entered or will enter into contracts for the purchase and construction of
power generation equipment and REPG, or its subagent, acts as the bank's agent
in connection with administering the contracts for such equipment. Under the
agreement, the bank has agreed to provide up to a maximum aggregate amount of
$650 million. REPG and its subagents must cash collateralize their obligation to
administer the contracts. This cash collateral is approximately equivalent to
the total payments by the bank for the equipment, interest and other fees. As of
December 31, 2001, the bank had assumed contracts for the purchase of eleven
turbines, two heat recovery steam generators and one air-cooled condenser with
an aggregate cost of $398 million. REPG, or its designee, has the option at any
time to purchase or, at equipment completion, subject to certain conditions,
including the agreement of the bank to extend financing, to lease equipment, or
to assist in the remarketing of the equipment under terms specified in the
agreement. All costs, including the purchase commitment on the turbines, are the
responsibility of the bank. The cash collateral is deposited by REPG or an
affiliate into a collateral account with the bank and earns interest at the
London inter-bank offered rate (LIBOR) less 0.15%. Under certain circumstances,
the collateral deposit or a portion of it will be returned to REPG or its
designee. Otherwise it will be retained by the bank. At December 31, 2001, REPG
and its subsidiary had deposited $230 million into the collateral account. The
bank's payments for equipment under the contracts totaled $227 million as of
December 31, 2001. In January 2002, the bank sold to the parties to the
construction agency agreements discussed above, equipment contracts with a total
contractual obligation of $258 million under which payments and interest during
construction totaled $142 million. Accordingly, $142 million of our collateral
deposits were returned to Reliant Resources. As of December 31, 2001, there were
equipment contracts with a total contractual obligation of $140 million under
which payments during construction totaled $83 million. Currently this equipment
is not designated for current planned power generation construction projects.
Therefore, Reliant Resources anticipates that it will either purchase the
equipment, assist in the remarketing of the equipment or negotiate to cancel the
related contracts.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MARKET RISK
We are exposed to various market risks. These risks arise from transactions
entered into in the normal course of business and are inherent in our
consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risks
include exposures to commodity prices through trading and marketing and
non-trading activities, interest rates, foreign currency exchange rates and
equity prices. A description of each market risk category is set forth below:
- Commodity price risk results from exposures to changes in spot prices,
forward prices and price volatilities of commodities, such as
electricity, natural gas and other energy commodities.
- Interest rate risk primarily results from exposures to changes in the
level of borrowings and changes in interest rates.
The following table presents credit exposure by maturity for total trading
and marketing assets and non-trading derivative assets, net of collateral, as of
December 31, 2001 (in millions).
<Table>
<Caption>
EXPOSURE NET OF
CREDIT RATING EQUIVALENT 0-12 MONTHS 1 YEAR OR GREATER COLLATERAL
- ------------------------ ----------- ----------------- ---------------
AAA/Aaa.................................... $ 95 $ 41 $ 136
AA/Aa2..................................... 142 49 191
A/A2....................................... 860 185 1,045
BBB/Baa2................................... 660 355 1,015
BB/Ba2 or lower............................ 125 100 225
Unrated(1)(2).............................. 31 18 49
------ ---- ------
1,913 748 2,661
Less: Credit and other reserves............ 69 45 114
------ ---- ------
$1,844 $703 $2,547
====== ==== ======
</Table>
- ---------------
(1) For unrated counterparties, we perform financial statement analysis,
considering contractual rights and restrictions, and collateral, to create a
synthetic credit rating.
(2) In lieu of making an individual assessment of the credit of unrated
counterparties, we may make a determination that the collateral held in
respect of such obligations is sufficient to cover a substantial portion of
our exposure. In making this determination, we take into account various
factors, including market volatility.
(3) Collateral consists of cash and standby letters of credit.
38
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
Reliant Energy, Incorporated (Reliant Energy), together with its
subsidiaries (collectively, the Company), is a diversified international energy
services company that provides energy and energy services primarily in North
America and Western Europe. Reliant Energy is both an electric utility company
and a utility holding company through its wholly owned subsidiary Reliant Energy
Resources Corp. (RERC).
The Company's financial reporting business segments include the following:
Electric Operations, Natural Gas Distribution, Pipelines and Gathering,
Wholesale Energy, European Energy, Retail Energy, Latin America and Other
Operations. Electric Operations includes the operations of Reliant Energy HL&P,
an electric utility. Natural Gas Distribution consists of intrastate natural gas
sales to, and natural gas transportation and distribution for, residential,
commercial, industrial and institutional customers and some non-rate regulated
retail gas marketing operations to commercial and industrial customers.
Pipelines and Gathering includes the interstate natural gas pipeline operations
and the natural gas gathering and pipelines services businesses. Wholesale
Energy is engaged in the acquisition, development and operation of non-rate
regulated power generation facilities as well as the wholesale energy trading,
marketing, power origination and risk management services in North America.
European Energy is engaged in the operation of power generation facilities in
the Netherlands as well as wholesale energy trading and power origination
activities in Europe. Retail Energy consists of the Company's unregulated retail
electric operations, and has historically been reported in the Other Operations
business segment. Other Operations includes unallocated general corporate
expenses, a communications business and non-operating investments. Latin America
primarily consists of an electric utility and an electric cogeneration plant
located in Argentina. Wholesale Energy, European Energy, Retail Energy and
certain operations included within Other Operations are currently owned by
Reliant Resources.
Reliant Energy is in the process of separating its regulated and
unregulated businesses into two publicly traded companies. In December 2000,
Reliant Energy transferred a significant portion of its unregulated businesses
to Reliant Resources, Inc. (Reliant Resources) which, at the time, was a wholly
owned subsidiary. In May 2001, Reliant Resources conducted an initial public
offering (Offering) of approximately 20% of its common stock (59.8 million
shares of its common stock) at a price of $30 per share, and received net
proceeds from the Offering of $1.7 billion. After the Offering, Reliant Energy
owned approximately 80% of Reliant Resources. As of December 31, 2001, Reliant
Energy owns approximately 83% of Reliant Resources due to treasury stock
repurchases of $189 million during 2001 by Reliant Resources. As a result of the
Offering, the Company recorded directly into stockholders' equity as a component
of common stock a $509 million unrealized gain on the sale of subsidiaries'
stock. Pursuant to a master separation agreement between Reliant Energy and
Reliant Resources, Reliant Resources used $147 million of the net proceeds to
repay certain indebtedness owed to Reliant Energy. In connection with the
Offering, Reliant Energy converted $1.7 billion of intercompany indebtedness
owed by Reliant Resources and its subsidiaries prior to the closing of the
Offering to equity as a capital contribution to Reliant Resources. In December
2001, Reliant Energy's shareholders approved an agreement and plan of merger by
which the following will occur (which we refer to as the Restructuring):
- CenterPoint Energy will become the holding company for Reliant Energy and
its subsidiaries;
- Reliant Energy and its subsidiaries will become subsidiaries of
CenterPoint Energy; and
- each share of Reliant Energy common stock will be converted into one
share of CenterPoint Energy common stock.
After the Restructuring, Reliant Energy plans, subject to further corporate
approvals, market and other conditions, to complete the separation of its
regulated and unregulated businesses by distributing the shares of common stock
of Reliant Resources that the Company owns to its shareholders (Distribution).
The Company's goal is to complete the Restructuring and subsequent Distribution
as quickly as possible after all
39
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the necessary conditions are fulfilled, including receipt of an order from the
Securities and Exchange Commission (SEC) granting the required approvals under
the Public Utility Holding Company Act of 1935 (1935 Act) and an extension from
the IRS of its private letter ruling that the Company has obtained regarding the
tax-free treatment of the Distribution. Although receipt or timing of regulatory
approvals cannot be assured, the Company believes it meets the standards for
such approvals. Reliant Energy currently expects to complete the Restructuring
and Distribution in the summer of 2002.
Effective December 1, 2000, Reliant Energy's board of directors approved a
plan to dispose of the Company's Latin America business segment through sales of
its assets. Accordingly, in its 2000 consolidated financial statements, the
Company reported the results of its Latin America business segment as
discontinued operations in accordance with Accounting Principles Board (APB)
Opinion No. 30 "Reporting the Results of Operations -- Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," (APB Opinion No. 30) for each of the three
years in the period ended December 31, 2000. On December 20, 2001, negotiations
for the sale of the remaining Latin America investments were terminated as a
result of the recent economic developments in Argentina. The Company will
continue to evaluate options related to the future disposition of these assets.
Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Consolidated Statements of Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by Emerging Issues Task Force (EITF) Issue No. 90-6
(EITF 90-6). For additional information regarding the disposal of the Latin
America business segment, see Note 19.
RESTATEMENT
On May 9, 2002, Reliant Resources determined that it had engaged in
same-day commodity trading transactions involving purchases and sales with the
same counterparty for the same volume at substantially the same price, which the
personnel who effected these transactions apparently did so with the sole
objective of increasing volumes. Reliant Resources commenced a review to
quantify the amount and assess the impact of these trades (round trip trades).
The Audit Committees of each of the Board of Directors of Reliant Energy and
Reliant Resources (Audit Committees) also directed an internal investigation by
outside legal counsel, with assistance by outside accountants, of the facts and
circumstances relating to the round trip trades and related matters.
The Company currently reports all trading, marketing and risk management
services transactions on a gross basis with such transactions being reported in
revenues and expenses except primarily for financial gas transactions such as
swaps. Therefore, the round trip trades were reflected in both the Company's
revenues and expenses. The round trip trades should not have been recognized in
revenues or expenses (i.e. they should have been reflected on a net basis).
However, since the round trip trades were done at the same volume and
substantially the same price, they had no impact on the Company's reported cash
flows, operating income or net income.
Based on Reliant Resources' review, Reliant Resources determined that it
engaged in such round trip trades in 1999, 2000 and 2001. The results of the
Audit Committees' investigation were consistent with the results of Reliant
Resources' review. The round trip trades were for 30 million megawatt hours
(MWh) of power and 182 billion cubic feet (Bcf) in 1999, 30 million MWh of power
in 2000, and 74 million MWh of power and 46 Bcf of natural gas in 2001. On May
13, 2002, Reliant Resources previously announced its preliminary findings of
round trip trades which had identified 30 million MWh of power in 1999, 30
million MWh of power in 2000, and 78 million MWh of power and 45 Bcf of natural
gas in 2001. In addition to the round trip trades reported on May 13, 2002,
Reliant Resources' review also identified an additional transaction in 1999
involving 182 Bcf of natural gas totaling $364 million, which based on available
information, Reliant
40
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Resources believes was also recorded with the sole objective of increasing
volumes but also resulted in increased revenues and fuel and cost of gas sold
expense.
In the course of Reliant Resources' review, Reliant Resources also
identified and determined to record on a net basis several transactions for
energy related services (not involving round trip trades) that totaled $85
million over the three year period ended December 31, 2001. These transactions
were originally recorded on a gross basis.
During 1999, 2000 and 2001, these transactions, referred to above,
collectively, had the effect of increasing revenues, fuel and cost of gas sold
expense and purchased power expense as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
1999 2000 2001
------ ------ ------
(IN MILLIONS)
Revenues................................................... $1,417 $1,070 $3,902
Fuel and cost of gas sold expense.......................... 376 27 208
Purchase power expense..................................... 1,041 1,043 3,694
</Table>
In addition, during the May 2001 through September 2001 time frame, Reliant
Resources entered into four structured transactions involving a series of
forward or swap contracts to buy and sell an energy commodity in 2001 and to buy
and sell an energy commodity in 2002 or 2003 (four structured transactions). The
four structured transactions were intended to increase future cash flow and
earnings and to increase certainty associated with future cash flow and
earnings, albeit at the expense of 2001 cash flow and earnings. Each series of
contracts in a structure were executed contemporaneously with the same
counterparty and were for the same commodities, quantities and locations. The
contracts in each structure were offsetting in terms of physical attributes. The
transactions that settled in 2001 were previously recorded on a gross basis with
such transactions being reported in revenues and expenses which resulted in $1.5
billion of revenues, $364 million in fuel and cost of gas sold and $1.2 billion
of purchased power expense being recognized during the period from May 2001
through December 31, 2001. Having further reviewed the transactions, Reliant
Resources now believes these transactions should have been accounted for on a
net basis.
During the fourth quarter of 2000, two power generation swap contracts with
a fair value of $261 million were terminated and replaced with a substantially
similar contract providing for physical delivery and designated to hedge
electric generation. The termination of the original contracts and execution of
the replacement contract represented a substantive modification to the original
contract. As a result, upon termination of the original contracts, a contractual
liability representing the fair value of the original contracts and a deferred
asset of equal amount should have been recorded. As of January 1, 2001, in
connection with the adoption of Statement of Financial Accounting Standards
(SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities,"
as amended (SFAS No. 133), the deferred asset should have been recorded as a
transition adjustment to other comprehensive loss. The liability and transition
adjustment should have been amortized on a straight-line basis over the term of
the power generation contract replacing the terminated power generation
contracts (through May 2004). The Company previously did not give accounting
recognition to these transactions. As a result, the Company has restated its
Consolidated Balance Sheets as of December 31, 2000 and 2001 and the Statements
of Consolidated Stockholders' Equity and Comprehensive Income for the year ended
December 31, 2001, to appropriately account for these transactions as described
above. The restatement had no impact on the Company's reported consolidated cash
flows, operating income or net income.
The consolidated financial statements for 1999, 2000 and 2001 have been
restated from amounts previously reported to reflect all of the transactions
described herein. In addition, the unaudited quarterly financial data for the
interim periods ended March 31, 2001, June 30, 2000 and 2001, and September 30,
2000 and 2001 have been restated from amounts previously reported to reflect all
of the transactions described
41
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
herein. The unaudited restated condensed quarterly financial statement
information for the quarters ended March 31, 2001, June 30, 2000 and 2001,
September 30, 2000 and 2001, and December 31, 2000 and 2001 have been included
in Note 17. The restatement had no impact on previously reported consolidated
cash flows, operating income or net income. A summary of the principal effects
of the restatement are as follows for 1999, 2000 and 2001: (Note -- Those line
items for which no change in amounts is shown were not affected by the
restatement.)
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 1999
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
Revenues.................................................... $13,794 $15,211
Expenses:
Fuel and Cost of Gas Sold................................. 6,331 6,707
Purchased Power........................................... 3,095 4,136
Other Expenses............................................ 3,109 3,109
------- -------
Total.................................................. 12,535 13,952
------- -------
Operating Income............................................ 1,259 1,259
Other Income, net........................................... 1,305 1,305
Income Tax Expense.......................................... (899) (899)
------- -------
Income Before Extraordinary Loss............................ 1,665 1,665
Extraordinary Loss.......................................... (183) (183)
------- -------
Net Income Attributable to Common Stockholders.............. $ 1,482 $ 1,482
======= =======
</Table>
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2000
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
Revenues.................................................... $28,269 $29,339
Expenses:
Fuel and Cost of Gas Sold................................. 15,050 15,077
Purchased Power........................................... 7,580 8,623
Other Expenses............................................ 3,802 3,802
------- -------
Total.................................................. 26,432 27,502
------- -------
Operating Income............................................ 1,837 1,837
Other Expense, net.......................................... (1,079) (1,079)
Income Tax Expense.......................................... (318) (318)
------- -------
Income Before Extraordinary Gain............................ 440 440
Extraordinary Gain.......................................... 7 7
------- -------
Net Income Attributable to Common Stockholders.............. $ 447 $ 447
======= =======
</Table>
42
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2001
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
Revenues.................................................... $40,810 $46,226
Expenses:
Fuel and Cost of Gas Sold................................. 19,504 20,075
Purchased Power........................................... 15,127 19,972
Other Expenses............................................ 4,186 4,186
------- -------
Total.................................................. 38,817 44,233
------- -------
Operating Income............................................ 1,993 1,993
Other Expense, net.......................................... (574) (574)
Income Tax Expense.......................................... (500) (500)
------- -------
Income Before Cumulative Effect of Accounting Change........ 919 919
Cumulative Effect of Accounting Change, net of tax.......... 61 61
------- -------
Net Income Attributable to Common Stockholders.............. $ 980 $ 980
======= =======
</Table>
43
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
DECEMBER 31, 2000
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
ASSETS
CURRENT ASSETS:
Other current assets...................................... $ 279 $ 203
Other..................................................... 9,634 9,634
------- -------
Total current assets.............................. 9,913 9,837
------- -------
OTHER ASSETS:
Other noncurrent assets................................... 932 747
Property, plant and equipment and other assets............ 21,115 21,115
------- -------
Total other assets................................ 22,047 21,862
------- -------
TOTAL ASSETS...................................... $31,960 $31,699
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Other current liabilities................................. $ 706 $ 630
Other..................................................... 14,939 14,939
------- -------
Total current liabilities......................... 15,645 15,569
OTHER LIABILITIES:
Other liabilities......................................... 1,048 863
Other..................................................... 4,074 4,074
------- -------
Total other liabilities........................... 5,122 4,937
------- -------
LONG-TERM DEBT.............................................. 4,996 4,996
------- -------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES.............. 9 9
------- -------
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS........................... 706 706
------- -------
STOCKHOLDERS' EQUITY:
Cumulative Preferred Stock................................ 10 10
Common Stock.............................................. 3,257 3,257
Treasury Stock............................................ (121) (121)
Unearned ESOP............................................. (161) (161)
Retained earnings......................................... 2,520 2,520
Accumulated other comprehensive loss...................... (23) (23)
------- -------
Stockholders' equity................................. 5,482 5,482
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........ $31,960 $31,699
======= =======
</Table>
44
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
DECEMBER 31, 2001
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
ASSETS
CURRENT ASSETS.............................................. $ 6,249 $ 6,249
PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS.............. 24,432 24,432
------- -------
TOTAL ASSETS...................................... $30,681 $30,681
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Non-trading derivative liabilities........................ $ 472 $ 396
Accumulated deferred income taxes, net.................... 359 386
Other..................................................... 8,875 8,875
------- -------
Total current liabilities......................... 9,706 9,657
------- -------
OTHER LIABILITIES:
Accumulated deferred income taxes, net.................... 2,308 2,346
Non-trading derivative liabilities........................ 649 540
Other..................................................... 3,785 3,785
------- -------
Total other liabilities........................... 6,742 6,671
------- -------
LONG-TERM DEBT.............................................. 5,742 5,742
------- -------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES.............. 1,047 1,047
------- -------
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS............................. 706 706
------- -------
STOCKHOLDERS' EQUITY:
Common Stock.............................................. 3,897 3,897
Unearned ESOP............................................. (132) (132)
Retained earnings......................................... 3,177 3,177
Accumulated other comprehensive loss...................... (204) (84)
------- -------
Stockholders' equity................................. 6,738 6,858
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY........ $30,681 $30,681
======= =======
</Table>
The restatement did not impact earnings per share for 1999, 2000 and 2001,
the Statements of Consolidated Cash Flows for 1999, 2000 and 2001, the
Statements of Consolidated Comprehensive Income for 1999 and 2000 or the
Statements of Consolidated Stockholders' Equity as of December 31, 1999 and
2000.
In addition to the round trip trades described above, Reliant Resources'
review and the Audit Committees' investigation also considered other
transactions executed on the same day at the same volume, price and delivery
terms and with the same counterparty. These transactions were executed in the
normal course of Reliant Resources' trading and marketing activities, and were
historically reported on a gross basis, and were not material.
Beginning with the quarter ended September 30, 2002, the Company will
report all energy trading and marketing activities on a net basis in the
Statements of Consolidated Income pursuant to Emerging Issues
45
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Task Force Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities".
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(d) REVENUES
The Company records revenue for electricity and natural gas sales and
services to retail customers, except for certain contracted sales to large
commercial, industrial and institutional customers, under the accrual method and
these revenues are generally recognized upon delivery. Pipelines and Gathering
record revenues as transportation services are provided. Energy sales and
services not billed by month-end are accrued based upon estimated energy and
services delivered. Domestic non-rate regulated electric power and other
non-rate regulated energy services are sold at market-based prices through
existing power exchanges or through third-party contracts. Prior to January 1,
2001, energy revenues related to the Company's power generation facilities in
Europe were generated under a regulated pricing structure, which included
compensation for the cost of fuel, capital and operation and maintenance
expenses. The wholesale electric market in the Netherlands opened to competition
on January 1, 2001. Accordingly, beginning in 2001, electric power and other
energy services in Europe are sold at market-based prices or through third-party
contracts.
The Company's energy trading, marketing, power origination and risk
management services activities and contracted sales of electricity to large
commercial, industrial and institutional customers are accounted for under
mark-to-market accounting. Under the mark-to-market method of accounting,
financial instruments and contractual commitments are recorded at fair value in
revenues upon contract execution. The net changes in their fair values are
recognized in the Statements of Consolidated Income as revenues in the period of
change. Trading and marketing revenues related to the physical sale of natural
gas, electric power and other energy related commodities are recorded on a gross
basis in the delivery period. For additional discussion regarding trading and
marketing revenue recognition and the related estimates and assumptions that can
affect reported amounts of such revenues, see Note 5.
The gains and losses related to financial instruments and contractual
commitments qualifying and designated as hedges related to the sale of electric
power and sales and purchases of natural gas are recognized in the same period
as the settlement of the underlying physical transaction. These realized gains
and losses are included in operating revenues and operating expenses in the
Statements of Consolidated Income. For additional discussion, see Note 5.
(e) LONG-LIVED ASSETS AND INTANGIBLES
The Company records property, plant and equipment at historical cost. The
Company recognizes repair and maintenance costs incurred in connection with
planned major maintenance, such as turbine and generator overhauls, control
system upgrades and air conditioner replacements, under the "accrual in advance"
method for its non-rate regulated power generation operations acquired or
developed prior to December 31, 1999. Planned major maintenance cycles primarily
range from two to ten years. Under the accrual in advance method, the Company
estimates the costs of planned major maintenance and accrues the related expense
over the maintenance cycle. As of December 31, 2000 and 2001, the Company's
maintenance reserve was $27 million and $19 million, respectively, of which $20
million and $17 million, respectively, were included in other long-term
liabilities and the remainder in other current liabilities. The Company expenses
all other repair and maintenance costs as incurred. Property, plant and
equipment includes the following:
<Table>
<Caption>
DECEMBER 31,
ESTIMATED USEFUL -----------------
LIVES (YEARS) 2000 2001
---------------- ------- -------
(IN MILLIONS)
Electric........................................... 5-75 $18,754 $20,092
Natural gas distribution........................... 5-50 1,809 2,002
Pipelines and gathering............................ 5-75 1,582 1,627
Other property..................................... 3-40 247 450
------- -------
Total............................................ 22,392 24,171
Accumulated depreciation and amortization.......... (7,132) (8,357)
------- -------
Property, plant and equipment, net............ $15,260 $15,814
======= =======
</Table>
46
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Goodwill has been
amortized on a straight-line basis over 5 to 40 years. See Note 3 and the
following table for additional information regarding goodwill and the related
amortization periods.
<Table>
<Caption>
DECEMBER 31,
ESTIMATED USEFUL ---------------
LIVES (YEARS) 2000 2001
---------------- ------ ------
(IN MILLIONS)
Reliant Energy Resources Corp. (RERC Corp.).......... 40 $1,955 $1,955
Reliant Energy Mid-Atlantic Power Holdings, LLC...... 35 7 5
Reliant Energy Power Generation Benelux N.V. ........ 30 897 877
Florida Generation Plant............................. 35 2 2
California Generation Plants......................... 30 70 70
Reliant Energy Services, Inc. ....................... 40 131 131
Other................................................ 5-35 64 45
------ ------
Total.............................................. 3,126 3,085
Accumulated amortization............................. (222) (303)
Foreign currency exchange impact..................... (107) (150)
------ ------
Total goodwill, net................................ $2,797 $2,632
====== ======
</Table>
The Company recognizes specifically identifiable intangibles, including air
emissions regulatory allowances and water rights and permits, when specific
rights and contracts are acquired. As of December 31, 2000 and 2001, specific
intangibles were $284 million and $315 million, respectively. The Company
amortizes air emissions regulatory allowances primarily on a units-of-production
basis as utilized. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range between 5 and 35 years.
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. An impairment analysis
of generating facilities requires estimates of possible future market prices,
load growth, competition and many other factors over the lives of the
facilities. A resulting impairment loss is highly dependent on these underlying
assumptions. During 2001, the Company determined equipment and goodwill
associated with its Communications business was impaired and accordingly
recognized $22 million of fixed asset impairments and $19 million of goodwill
impairments (see Note 20). For discussion of goodwill impairment analysis in
2002, see Note 2(q).
During December 2001, the Company evaluated its European Energy business
segment's long-lived assets and goodwill for impairment. As of December 31,
2001, pursuant to Statement of Financial Accounting Standards (SFAS) No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" (SFAS No. 121), no impairment had been indicated. For discussion
of goodwill impairment analysis in 2002, see Note 2(q).
During the fourth quarter of 2001, the Distribution of Reliant Resources
was deemed to be a probable event. As Reliant Resources has an option, subject
to the completion of the Distribution, to purchase the Company's Texas
generation assets in 2004 (see Note 4(b)), the Company was required to evaluate
these assets for potential impairment in accordance with SFAS No. 121, due to an
expected decrease in the number of years the Company expects to hold and operate
these assets. As of December 31, 2001, no impairment had been indicated. The
Company anticipates that future events, such as the expected public offering of
the Company's Texas generation operations (see Note 4(b)), or change in the
estimated holding period of the Texas generation assets, will require the
Company to re-evaluate these assets for impairment between now and 2004. If an
impairment is indicated, it could be material and will not be fully recoverable
through the 2004 true-up proceeding calculations (see Note 4(a)).
47
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Texas Electric Restructuring Law provides the Company recovery of the
regulatory book value of its Texas generating assets for the amount the
regulatory book value exceeds the estimated market value. If the Texas
generating assets are sold to Reliant Resources, or to a third party in the
future, a loss on sale of these assets, or an impairment of the recorded
recoverable electric generation plant mitigation regulatory asset (see Note
2(f)), will occur to the extent the recorded book value of the Texas generating
assets exceeds the regulatory book value. As of December 31, 2001, the recorded
book value was $638 million in excess of the regulatory book value. This amount
declines each year as the recorded book value is depreciated and increases by
the amount of non-environmental capital expenditures. For further discussion of
the difference between the regulatory book value and the recorded book value,
see Note 4.
(f) REGULATORY ASSETS AND LIABILITIES
The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of transmission and distribution operations of Reliant Energy HL&P and
the utility operations of Natural Gas Distribution and to some of the accounts
of Pipelines and Gathering. For information regarding Reliant Energy HL&P's
electric generation operations' discontinuance of the application of SFAS No. 71
in 1999 and the effect on its regulatory assets and the Texas Electric Choice
Plan (Texas Electric Restructuring Law), see Note 4(a).
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2000 and 2001:
<Table>
<Caption>
DECEMBER 31,
----------------
2000 2001
------ -------
(IN MILLIONS)
Recoverable impaired plant costs, net....................... $ 281 $ --
Recoverable electric generation related regulatory assets,
net....................................................... 1,150 160
Securitized regulatory asset................................ -- 740
Regulatory tax asset, net................................... 186 111
Unamortized loss on reacquired debt......................... 66 62
Recoverable electric generation plant mitigation............ -- 1,967
Excess mitigation liability................................. -- (1,126)
Other long-term assets/liabilities.......................... 6 3
------ -------
Total..................................................... $1,689 $ 1,917
====== =======
</Table>
If, as a result of changes in regulation or competition, the Company's
ability to recover these assets and liabilities would not be assured, then
pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the
Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121,
the Company would be required to write off or write down these regulatory assets
and liabilities. In addition, the Company would be required to determine any
impairment to the carrying costs of plant and inventory assets. See Note 4(a)
for a discussion of the discontinuation of SFAS No. 71 related to Reliant Energy
HL&P's electric generation operations.
Through December 31, 2001, the Texas Utility Commission provided for the
recovery of most of Reliant Energy HL&P's fuel and purchased power costs from
customers through a fixed fuel factor included in electric rates. Included in
the above table in recoverable electric generation related regulatory assets,
net are $558 million and $200 million of regulatory assets related to the
recovery of fuel costs as of December 31, 2000 and 2001.
In December 2001, the Company recorded a regulatory asset for recoverable
electric generation plant mitigation for $2.0 billion and recorded a regulatory
liability of $1.1 billion for excess mitigation, resulting in net regulatory
assets of $841 million on which the Company will not earn a return and which are
not included in the Company's rate base. Recoverable electric plant generation
regulatory assets are anticipated to be recovered in the 2004 true-up
proceedings as further discussed in Note 4(a). The Company is entitled to
48
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
recover its full amount of stranded costs in the 2004 true-up proceeding. That
recovery would include any amounts whose earlier mitigation was prevented by
excess mitigation credits and the reversal of redirected depreciation ordered by
the Texas Utility Commission.
In 2001, the Company monetized $738 million of regulatory assets in a
securitization financing authorized by the Texas Utility Commission pursuant to
the Texas Electric Restructuring Law. For additional information regarding the
securitization financing, see Note 4(a).
For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets and the related amortization
during 1999, 2000 and 2001, see Notes 2(g) and 4(a).
(l) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES
In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value within other long-term
assets in the Company's Consolidated Balance Sheets and any unrealized gain or
loss, net of tax, as a separate component of stockholders' equity and
accumulated other comprehensive (loss) income. In accordance with SFAS No. 115,
the Company reports "trading" securities at estimated fair value in the
Company's Consolidated Balance Sheets, and any unrealized holding gains and
losses are recorded as other income (expense) in the Company's Statements of
Consolidated Income.
49
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2000 and 2001, the Company held "available-for-sale"
debt and equity securities in its nuclear decommissioning trust, which is
reported at its fair value of $159 million and $169 million, respectively, in
the Company's Consolidated Balance Sheets in other long-term assets. Any
unrealized losses or gains are accounted for in accordance with SFAS No. 71 as a
regulatory asset/liability.
In addition, as of December 31, 2000 and 2001, the Company held marketable
equity securities of $5 million and $12 million, respectively, classified as
"available-for-sale." At December 31, 2000, the accumulated unrealized loss, net
of tax, relating to these equity securities was $2 million. At December 31,
2001, the accumulated unrealized gain, net of tax, relating to these equity
securities was $6 million.
During 2000, pursuant to SFAS No. 115, the Company incurred a pre-tax
impairment loss equal to the $27 million of cumulative unrealized losses that
had been charged to accumulated other comprehensive loss through December 31,
1999. Management's determination to recognize this impairment resulted from a
combination of events occurring in 2000 related to this investment. These events
affecting the investment included changes occurring in the investment's senior
management, announcement of significant restructuring charges and related
downsizing for the entity, reduced earnings estimates for this entity by
brokerage analysts and the bankruptcy of a competitor of the investment in the
first quarter of 2000. These events, coupled with the stock market value of the
Company's investment in these securities continuing to be below the Company's
cost basis, caused management to believe the decline in fair value of these
"available-for-sale" securities to be other than temporary.
As of December 31, 2000 and 2001, the Company held an investment in AOL
Time Warner common stock, which was classified as a "trading" security. For
information regarding the Company's investment in AOL Time Warner, Inc. common
stock, see Note 8.
As of December 31, 2000, the Company did not hold debt or equity securities
that are classified as "trading", other than its investment in AOL Time Warner.
As of December 31, 2001, the Company held equity securities classified as
"trading" totaling $1 million, other than its investment in AOL Time Warner. The
Company recorded unrealized holding gains on "trading" securities, excluding
unrealized gains and losses related to the Company's investment in AOL Time
Warner, included in gains from investments in the Statements of Consolidated
Income of $16 million, $4 million and $5 million during 1999, 2000 and 2001,
respectively.
(q) NEW ACCOUNTING PRONOUNCEMENTS
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the SEC on December 3, 1999. SAB No. 101 summarizes certain of the SEC
staff's views in applying generally accepted accounting principles to revenue
recognition in financial statements. The consolidated financial statements
reflect the accounting guidance provided in SAB No. 101.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and
Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method of accounting and broadens the criteria for recording intangible
assets separate from goodwill. Recorded goodwill and intangibles will be
evaluated against these new criteria and may result in certain intangibles being
transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. SFAS
No. 142 provides for a nonamortization approach, whereby goodwill and certain
intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and written
down and charged to results of operations only in the periods in which the
recorded value of goodwill and certain intangibles with indefinite lives is more
than its fair value. The Company adopted the provisions of each statement which
apply to goodwill and intangible assets acquired prior to June 30, 2001 on
January 1, 2002. The adoption of SFAS No. 141 did not have a material impact on
the Company's historical results of operations or financial position. On January
1, 2002, the Company discontinued amortizing goodwill into the results of
operations pursuant to SFAS No. 142. The Company recognized $81 million of
goodwill amortization expense in the Statements of Consolidated Income during
2001, excluding a $19 million write-off of its Communications business goodwill
balance which was recorded as goodwill amortization expense (see Note 20). The
Company is in the process of determining further effects of adoption of SFAS No.
142 on its consolidated financial statements, including the review of goodwill
and certain intangible assets for impairment. The Company has not completed its
review pursuant to SFAS No. 142. However, based on the Company's preliminary
review, the Company believes an impairment of its European Energy business
segment goodwill is reasonably possible. As of December 31, 2001, net goodwill
associated with the European Energy business segment is $632 million. The
Company has not completed its preliminary review of its other business segments
with net goodwill totaling $2.0 billion. The Company anticipates finalizing its
review of goodwill and certain intangible assets during 2002.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
a liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. The Company plans to adopt SFAS No.
143 on January 1, 2003 and is in the process of determining the effect of
adoption on its consolidated financial statements. For certain operations
subject to cost of service rate regulation, the Company is permitted to include
annual charges for cost of removal and nuclear decommissioning costs in the
revenues charged to customers.
In August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment
or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121
and APB Opinion No. 30, while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not
expected to materially change the methods used by the Company to measure
impairment losses on long-lived assets, but may result in additional future
dispositions being reported as discontinued operations than was previously
permitted. The Company adopted SFAS No. 144 on January 1, 2002.
See Note 5 for the Company's adoption of SFAS No. 133 on January 1, 2001
and adoption of subsequent cleared guidance.
50
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(3) BUSINESS ACQUISITIONS
(a) RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
On May 12, 2000, a subsidiary of the Company purchased entities owning
electric power generating assets and development sites located in Pennsylvania,
New Jersey and Maryland having an aggregate net generating capacity of
approximately 4,262 MW. With the exception of development entities that were
sold to another subsidiary of Reliant Resources in July 2000, the assets of the
entities acquired are held by REMA. The purchase price for the May 2000
transaction was $2.1 billion. In 2002, the Company made an $8 million payment to
the prior owner for post-closing adjustments which resulted in an adjustment to
purchase price. The Company accounted for the acquisition as a purchase with
assets and liabilities of REMA reflected at their estimated fair values. The
Company's fair value adjustments related to the acquisition primarily included
adjustments in property, plant and equipment, air emissions regulatory
allowances, specific intangibles, materials and supplies inventory,
environmental reserves and related deferred taxes. The air emissions regulatory
allowances of $153 million are being amortized on a units-of-production basis as
utilized. The specific intangibles which relate to water rights and permits of
$43 million will be amortized over the estimated life of the related facility of
35 years. The excess of the purchase price over the fair value of the net assets
acquired of $5 million was recorded as goodwill and historically was amortized
over 35 years. The Company finalized these fair value adjustments in May 2001.
There were no additional material modifications to the preliminary adjustments
from December 31, 2000. Funds for the acquisition of REMA were made available
through commercial paper borrowings by a finance subsidiary, which borrowings
were supported by credit facilities.
The net purchase price of REMA was allocated and the fair value adjustments
to the seller's book value are as follows:
<Table>
<Caption>
PURCHASE PRICE FAIR VALUE
ALLOCATION ADJUSTMENTS
-------------- -----------
(IN MILLIONS)
Current assets.............................................. $ 85 $ (27)
Property, plant and equipment............................... 1,898 627
Goodwill.................................................... 5 (146)
Other intangibles........................................... 196 33
Other assets................................................ 3 (5)
Current liabilities......................................... (50) (13)
Other liabilities........................................... (39) (15)
------ -----
Total.................................................. $2,098 $ 454
====== =====
</Table>
Adjustments to property, plant and equipment, other intangibles which
includes air emissions regulatory allowances and other specific intangibles, and
environmental reserves included in other liabilities are based primarily on
valuation reports prepared by independent appraisers and consultants.
In August 2000, the Company, through subsidiaries, entered into separate
sale-leaseback transactions with each of three owner-lessors covering the
subsidiaries' respective 16.45%, 16.67% and 100% interests in the Conemaugh,
Keystone and Shawville generating stations, respectively, acquired as part of
the REMA acquisition. As lessee, Reliant Resources leases an interest in each
facility from each owner-lessor under a facility lease agreement. As
consideration for the sale of the Company's interest in the facilities, the
Company received $1.0 billion in cash. The Company used the $1.0 billion of sale
proceeds to repay certain commercial paper borrowings as described above.
The Company's results of operations include the results of REMA only for
the period beginning May 12, 2000. The following table presents selected actual
financial information and unaudited pro forma information for 1999 and 2000, as
if the acquisition had occurred on November 24, 1999 and January 1, 2000, as
applicable. Pro forma information for operations prior to November 24, 1999
would not be meaningful since historical financial results of the business and
the revenue generating activities underlying that period are substantially
different from the wholesale generation activities that REMA has been engaged in
after November 24, 1999. Pro forma amounts also give effect to the sale and
leaseback of interests in three of the REMA generating plants, which were
consummated in August 2000.
51
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000
------------------- -------------------
UNAUDITED UNAUDITED
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS)
Revenues..................................... $13,794 $13,824 $28,269 $28,436
Income after tax and before extraordinary
items...................................... 1,666 1,656 440 431
Net income attributable to common
stockholders............................... 1,482 1,472 447 438
</Table>
These unaudited pro forma results, based on assumptions deemed appropriate
by the Company's management, have been prepared for informational purposes only
and are not necessarily indicative of the amounts that would have resulted if
the acquisition of the REMA entities had occurred on November 24, 1999 and
January 1, 2000, as applicable. Purchase-related adjustments to the results of
operations include the effects on depreciation and amortization, interest
expense and income taxes.
(b) RELIANT ENERGY POWER GENERATION BENELUX N.V.
Effective October 7, 1999, a subsidiary of the Company acquired REPGB, a
Dutch electric generation company, for a total net purchase price, payable in
Dutch Guilders (NLG), of $1.9 billion based on an exchange rate on October 7,
1999 of 2.06 NLG per U.S. dollar. The aggregate purchase price paid in 1999 by
the Company consisted of $833 million in cash. On March 1, 2000, under the terms
of the acquisition agreement, the Company funded the remaining purchase
obligation for $982 million. A portion ($596 million) of this obligation was
financed with a three-year term loan facility obtained in the first quarter of
2000.
The Company recorded the REPGB acquisition under the purchase method of
accounting, with assets and liabilities of REPGB reflected at their estimated
fair values. As outlined in the table below, the Company's fair value
adjustments related to the acquisition of REPGB primarily included increases in
property, plant and equipment, long-term debt, severance liabilities,
post-employment benefit liabilities and deferred foreign taxes. Additionally, a
$19 million receivable was recorded in connection with the acquisition as the
selling shareholders agreed to reimburse REPGB for some obligations incurred
prior to the purchase of REPGB. Adjustments to property, plant and equipment are
based on valuation reports prepared by independent appraisers and consultants.
The excess of the purchase price over the fair value of net assets acquired of
$877 million was recorded as goodwill and was historically amortized on a
straight-line basis over 30 years. The Company finalized these fair value
adjustments in September 2000. The Company finalized a severance plan (REPGB
Plan) in connection with the REPGB acquisition in September 2000 (commitment
date) and in accordance with EITF Issue No. 95-3 "Recognition of Liabilities in
Connection with a Purchase Business Combination," recorded this liability of $19
million in the third quarter of 2000. During 2001, the Company utilized $8
million of the reserve for the REPGB Plan. As of December 31, 2001, the
remaining severance liability is $11 million. The majority of the $11 million of
remaining severance liability will be disbursed in accordance with the terms and
conditions outlined by a collective labor bargaining agreement regarding
employees near retirement age (Social Plan) in accordance with applicable Dutch
labor law. The Social Plan, which by formula defines termination benefits,
prescribes a payout period for up to five years for an employee subsequent to
termination date. In the fourth quarter of 2001, the Dutch taxing authority
finalized REPGB's tax basis of property, plant and equipment as of October 1999.
As a result, the Company recorded an adjustment to decrease goodwill and
accumulated deferred tax liability by $5 million in the fourth quarter of 2001.
As of December 31, 2001, the tax basis of other certain assets and liabilities
has not been finalized.
In connection with the acquisition of REPGB, the Company developed a
comprehensive business process reengineering and employee severance plan
intended to make REPGB competitive in the deregulated Dutch electricity market
that began January 1, 2001. The REPGB Plan's initial conceptual formulation was
initiated prior to the acquisition of REPGB in October 1999. The finalization of
the REPGB Plan was approved and
52
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
completed in September 2000. The Company identified 195 employees who were
involuntarily terminated in REPGB's following functional areas: plant operations
and maintenance, procurement, inventory, general and administrative, legal,
finance and support. The Company has notified all employees identified under the
severance component of the REPGB Plan that they are subject to involuntary
termination and the majority of terminations occurred during 2001. The
termination benefits under the REPGB Plan are governed by REPGB's Social Plan, a
collective bargaining agreement between REPGB and its various representative
labor unions signed in 1998. The Social Plan provides defined benefits for
involuntarily severed employees depending upon age, tenure and other factors,
and was agreed to by the management of REPGB as a result of the anticipated
deregulation of the Dutch electricity market. The Social Plan is still in force
and binding on the current management of the Company and REPGB. The Company is
still executing the REPGB Plan as of the date of these consolidated financial
statements.
The net purchase price of REPGB was allocated and the fair value
adjustments to the seller's book value are as follows:
<Table>
<Caption>
PURCHASE PRICE FAIR VALUE
ALLOCATION ADJUSTMENTS
-------------- -----------
(IN MILLIONS)
Current assets.............................................. $ 244 $ 34
Property, plant and equipment............................... 1,899 719
Goodwill.................................................... 877 877
Current liabilities......................................... (336) --
Deferred taxes.............................................. (76) (76)
Long-term debt.............................................. (422) (87)
Other long-term liabilities................................. (244) (35)
------ ------
Total..................................................... $1,942 $1,432
====== ======
</Table>
The following table presents selected actual financial information for 1999
and unaudited pro forma information for 1999, as if the acquisition of REPGB had
occurred on January 1, 1999. The pro forma results are based on assumptions
deemed appropriate by the Company's management, have been prepared for
informational purposes only and are not necessarily indicative of the
consolidated results that would have resulted if the acquisition of REPGB had
occurred on January 1, 1999. Purchase related adjustments to results of
operations include amortization of goodwill, interest expense and the effects on
depreciation and amortization of the assessed fair value of some of REPGB's net
assets and liabilities.
<Table>
<Caption>
1999
-------------------
ACTUAL PRO FORMA
------- ---------
(IN MILLIONS)
Revenues.................................................... $13,794 $14,371
Net income attributable to common stockholders.............. 1,482 1,455
</Table>
(c) FLORIDA GENERATION PLANT PURCHASE
On October 6, 1999, the Company purchased a steam turbine generation plant
(Indian River) with a net generating capacity of 619 MW from a Florida
municipality (Municipality) for a net purchase price of $188 million. Indian
River, located near Titusville, Florida, consists of three conventional steam
generation units fueled by both oil and natural gas. Under the Company's
ownership, the units will sell up to 578 MW of power generation from Indian
River to the Municipality through a power purchase agreement that was originally
scheduled to expire in September 2003, but has been extended through September
2007. During the option period, the Municipality has the right to purchase up to
500 MW for the first two years of the option period and 300 MW for the final two
years. Any excess power generated by the plant may be sold to other utilities
and rural electric cooperatives within the state and other entities within the
Florida wholesale market.
53
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company recorded the acquisition under the purchase method of accounting.
The purchase price has been allocated to assets acquired and liabilities assumed
based on their estimated fair market values at the date of acquisition. The
Company's fair value adjustments related to the acquisition of Indian River
primarily included increases in property, plant and equipment, specific
intangibles related to water rights and permits, major maintenance reserves and
related deferred taxes. The specific intangibles of $112 million are being
amortized over their contractual lives of 35 years. The Company finalized these
fair value adjustments during September 2000. There were no material adjustments
made to the purchase allocation subsequent to December 31, 1999.
Net purchase price of Indian River was allocated as follows (in millions):
<Table>
Current assets.............................................. $ 15
Property, plant and equipment............................... 93
Goodwill.................................................... 2
Other intangibles........................................... 112
Major maintenance reserve................................... (3)
Other long-term liabilities................................. (31)
----
Total..................................................... $188
====
</Table>
The Company's results of operations include Indian River's results of
operations only for the period beginning with the October 6, 1999 acquisition
date. Pro forma information has not been presented for Indian River for 1999.
Pro forma information would not be meaningful since historical financial results
of the business and the revenue generating activities underlying that period as
described below are substantially different from the wholesale generation
activities that Indian River has been engaged in after October 6, 1999. Prior to
the Company's acquisition, the acquired Indian River generation operations were
fully integrated with, and its results of operations were consolidated into, the
Municipality's vertically-integrated utility operations. In addition, prior to
the Company's acquisition, the electric output of these facilities was sold
based on rates set by regulatory authorities and are not indicative of these
assets' future operating results as a wholesale electricity provider.
(4) REGULATORY MATTERS
(a) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC
GENERATION OPERATIONS
In June 1999, the Texas legislature adopted the Texas Electric
Restructuring Law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail electric
competition. Retail pilot projects allowing competition for up to 5% of each
utility's load in all customer classes began in the third quarter of 2001, and
retail electric competition for all other customers began in January 2002. In
preparation for competition, the Company made significant changes in the
electric utility operations it conducts through its electric utility division,
Reliant Energy HL&P. In addition, the Texas Utility Commission issued a number
of new rules and determinations in implementing the Texas Electric Restructuring
Law.
The Texas Electric Restructuring Law defined the process for competition
and created a transition period during which most utility rates were frozen at
rates not in excess of their then-current levels. The Texas Electric
Restructuring Law provided for utilities to recover their generation related
stranded costs and regulatory assets (as defined in the Texas Electric
Restructuring Law).
Retail Choice. Under the Texas Electric Restructuring Law, beginning
January 1, 2002, retail customers of most investor owned electric utilities in
Texas became eligible to purchase their electricity from any of a number of
"retail electric providers," which are certified by the Texas Utility
Commission. Retail electric providers may not own or operate generation assets
and their sales prices are not subject to traditional
54
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cost-of-service rate regulation. Retail electric providers that are affiliates
of electric utilities may compete substantially statewide for these sales, but
prices they charge within the affiliated electric utility's traditional service
territory are subject to some limitations at the outset of retail choice, as
described below. The Texas Utility Commission has prescribed regulations
governing quality, reliability and other aspects of service from retail electric
providers. Reliant Resources intends to compete in the Texas retail market and,
as a result, has certified three of its subsidiaries as retail electric
providers.
Unbundling. As of January 1, 2002, electric utilities in Texas such as
Reliant Energy HL&P unbundled their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Texas Electric Restructuring Law, the Company submitted a
plan in January 2000 that was later amended and updated to accomplish the
required separation (the Business Separation Plan). For additional information
regarding the Business Separation Plan, see Note 4(b). The transmission and
distribution business will continue to be subject to cost-of-service rate
regulation and will be responsible for the delivery of electricity to retail
customers. The Company plans to transfer the Texas generation facilities that
were formerly part of the Reliant Energy HL&P integrated utility (Texas
generation business) to an indirect wholly owned partnership (Texas Genco) in
connection with the Restructuring. As a result of these changes, the Company's
Texas generation operations will no longer be conducted as part of an integrated
utility and will comprise a new business segment in 2002, Electric Generation.
Additionally, these operations will not be part of the Company's business if
they are acquired in 2004 by Reliant Resources pursuant to an option agreement
as described below. At that time, Reliant Resources will be an unaffiliated
company as a result of the planned Distribution.
Generation. Power generators began selling electric energy to wholesale
purchasers, including retail electric providers, at unregulated prices on
January 1, 2002. To facilitate a competitive market, each power generation
company affiliated with a transmission and distribution utility is required to
sell at auction 15% of the output of its installed generating capacity. The
first auction was held in September 2001 for power delivered beginning January
1, 2002. This obligation continues until January 1, 2007 unless before that date
the Texas Utility Commission determines that at least 40% of the quantity of
electric power consumed in 2000 by residential and small commercial load in the
electric utility's service area is being served by retail electric providers
other than the affiliated retail electric provider. See Note 4(b) for
information regarding the capacity auctions and the effect of the Business
Separation Plan on the Company. Texas Genco plans to auction all of its
remaining capacity (less approximately 10% withheld to provide for unforeseen
outages) during the time period prior to Reliant Resources' exercise of the
Texas Genco option discussed below. Pursuant to the Business Separation Plan,
Reliant Resources is entitled to purchase, at prices established in these
auctions, 50% (but no less than 50%) of the remaining capacity, energy and
ancillary services auctioned by Texas Genco.
Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 were
frozen until January 1, 2002. Pursuant to Texas Utility Commission regulations,
effective January 1, 2002, after the cycle meter read in January 2002, retail
rates charged to residential and small commercial customers by an affiliated
retail electric provider were reduced by 6% from the average rates (on a bundled
basis) in effect on January 1, 1999. Following adjustments for changes in fuel
prices, this actually resulted in a 17% rate reduction for Reliant Resources,
through its subsidiaries, as an affiliated retail provider. That reduced rate,
known as the "price to beat", is being charged by the affiliated retail electric
provider to residential and small commercial customers in the utility's service
area who have not elected service from another retail electric provider. The
affiliated retail electric provider may not offer different rates to residential
or small commercial customer classes in the utility's service area until the
earlier of the date the Texas Utility Commission determines that 40% of power
consumed by that class in the affiliated transmission and distribution utility's
service area is being served by non-affiliated retail electric providers or
January 1, 2005. In addition, the affiliated retail electric provider must make
the price to beat rate available to eligible consumers until January 1, 2007.
55
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stranded Costs. Reliant Energy HL&P will be entitled to recover its
stranded costs (i.e., the excess of net book value of generation assets (as
defined by the Texas Electric Restructuring Law) over the market value of those
assets) and its regulatory assets related to generation. The Texas Electric
Restructuring Law prescribes specific methods for determining the amount of
stranded costs and the details for their recovery. During the transition period
to deregulation (the Transition Period) which included 1998 and the first six
months of 1999, and extending through the base rate freeze period from July 1999
through 2001, the Texas Electric Restructuring Law provided that earnings above
a stated overall annual rate of return on invested capital be used to recover
the Electric Operations business segments' investment in generation assets
(Accelerated Depreciation). In addition, during the Transition Period, the
redirection of depreciation expense to generation assets that the Electric
Operation business segment would otherwise apply to transmission, distribution
and general plant assets was permitted for regulatory purposes (Redirected
Depreciation). See discussion of the accounting treatment of Accelerated
Depreciation and Redirected Depreciation for financial reporting purposes below
under "Accounting." We cannot predict the amount, if any, of these costs that
may not be recovered.
In accordance with the Texas Electric Restructuring Law, beginning on
January 1, 2002, and ending when the true-up proceeding is completed in January
2004, any difference between market power prices received in the generation
capacity auction and the Texas Utility Commission's earlier estimates of those
market prices will be included in the 2004 stranded cost true-up, as further
discussed below. This component of the true-up is intended to ensure that
neither the customers nor the Company are disadvantaged economically as a result
of the two-year transition period by providing this pricing structure.
On October 24, 2001, Reliant Energy Transition Bond Company LLC (Bond
Company), a Delaware limited liability company and direct wholly owned
subsidiary of Reliant Energy, issued $749 million aggregate principal amount of
its Series 2001-1 Transition Bonds pursuant to a financing order of the Texas
Utility Commission. Classes of the bonds have final maturity dates of September
15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015, and
bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. Scheduled
payments on the bonds are from 2002 through 2013. Net proceeds to the Bond
Company from the issuance were $738 million. The Bond Company paid Reliant
Energy $738 million for the transition property. Reliant Energy used the net
proceeds for general corporate purposes, including the repayment of
indebtedness.
The Transition Bonds are secured primarily by the "transition property,"
which includes the irrevocable right to recover, through non-bypassable
transition charges payable by certain retail electric customers, the qualified
costs of Reliant Energy HL&P authorized by the financing order. The holders of
the Bond Company's bonds have no recourse to any assets or revenues of Reliant
Energy, and the creditors of Reliant Energy have no recourse to any assets or
revenues (including, without limitation, the transition charges) of the Bond
Company. Reliant Energy has no payment obligations with respect to the
Transition Bonds except to remit collections of transition charges as set forth
in a servicing agreement between Reliant Energy and the Bond Company and in an
intercreditor agreement among Reliant Energy, the Bond Company and other
parties.
Costs associated with nuclear decommissioning will continue to be subject
to cost-of-service rate regulation and are included in a charge to transmission
and distribution customers. For further discussion of the effect of the Business
Separation Plan on funding of the nuclear decommissioning trust fund, see Note
4(b).
True-Up Proceeding. The Texas Electric Restructuring Law and current Texas
Utility Commission implementation guidance provide for a True-up Proceeding to
be initiated in January 2004. The purpose of the True-up Proceeding is to
quantify and reconcile the amount of stranded costs, the capacity auction
true-up, unreconciled fuel costs (see Note 2(f)), and other regulatory assets
associated with Reliant Energy HL&P's
56
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
electric generating operations that were not previously securitized through the
Transition Bonds. The True-up Proceeding will result in either additional
charges or credits being assessed on certain retail electric customers.
Accounting. Historically, Reliant Energy HL&P has applied the accounting
policies established in SFAS No. 71. Effective June 30, 1999, the Company
applied SFAS No. 101 to Reliant Energy HL&P's electric generation operations.
Reliant Energy HL&P's transmission and distribution operations continue to meet
the criteria of SFAS No. 71.
In 1999, the Company evaluated the effects that the Texas Electric
Restructuring Law would have on the recovery of its generation related
regulatory assets and liabilities. The Company determined that a pre-tax
accounting loss of $282 million existed because it believes only the economic
value of its generation related regulatory assets (as defined by the Texas
Electric Restructuring Law) will be recovered. Therefore, the Company recorded a
$183 million after-tax extraordinary loss in the fourth quarter of 1999.
Pursuant to EITF Issue No. 97-4, the remaining recoverable regulatory assets
will not be written off and will become associated with the transmission and
distribution portion of the Company's electric utility business. For details
regarding Reliant Energy HL&P's regulatory assets, see Note 2(f).
At June 30, 1999, the Company performed an impairment test of its
previously regulated electric generation assets pursuant to SFAS No. 121 on a
plant specific basis. Under SFAS No. 121, an asset is considered impaired, and
should be written down to fair value, if the future undiscounted net cash flows
expected to be generated by the use of the asset are insufficient to recover the
carrying amount of the asset. For assets that are impaired pursuant to SFAS No.
121, the Company determined the fair value for each generating plant by
estimating the net present value of future cash inflows and outflows over the
estimated life of each plant. The difference between fair value and net book
value was recorded as a reduction in the current book value. The Company
determined that $808 million of electric generation assets were impaired in
1999. Of this amount, $756 million related to the South Texas Project Electric
Generating Station (South Texas Project) and $52 million related to two
gas-fired generation plants. The Texas Electric Restructuring Law provides for
recovery of this impairment through regulated cash flows during the transition
period and through charges to transmission and distribution customers. As such,
a regulatory asset was recorded for an amount equal to the impairment loss and
was included on the Company's Consolidated Balance Sheets as a regulatory asset.
The Company recorded amortization expense related to the recoverable impaired
plant costs and other assets created from discontinuing SFAS No. 71 of $221
million in the third and fourth quarters of 1999, $329 million in 2000 and $258
million in 2001.
The impairment analysis requires estimates of possible future market
prices, load growth, competition and many other factors over the lives of the
plants. The resulting impairment loss is highly dependent on these underlying
assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must
finalize and reconcile stranded costs (as defined by the Texas Electric
Restructuring Law) in a filing with the Texas Utility Commission. Any positive
difference between the regulatory net book value and the fair market value of
the generation assets (as defined by the Texas Electric Restructuring Law) will
be collected through future charges. Any overmitigation of stranded costs may be
refunded by a reduction in future charges. This final reconciliation allows
alternative methods of third party valuation of the fair market value of these
assets, including outright sale, stock valuations and asset exchanges.
In order to reduce potential exposure to stranded costs related to
generation assets, Reliant Energy HL&P redirected $195 million and $99 million
of depreciation in 1998 and for the six months ended June 30, 1999,
respectively, from transmission and distribution related plant assets to
generation assets for regulatory and financial reporting purposes (Redirected
Depreciation). This redirection was in accordance with the Company's Transition
Plan. Subsequent to June 30, 1999, Redirected Depreciation expense could no
longer be recorded by the electric generation operations portion of Reliant
Energy HL&P for financial reporting purposes as this portion of electric
operations is no longer accounted for under SFAS No. 71. During the six months
ended December 31, 1999 and during 2000 and 2001, $99 million, $218 million and
$230 million in
57
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
depreciation expense, respectively, was redirected from transmission and
distribution for regulatory and financial reporting purposes and was established
as an embedded regulatory asset included in transmission and distribution
related plant and equipment balances. As of December 31, 2000 and 2001, the
cumulative amount of Redirected Depreciation for regulatory purposes was $611
million and $841 million, respectively, prior to the effects of the October 3,
2001 order discussed below.
Additionally, as allowed by the Texas Utility Commission, in an effort to
further reduce potential exposure to stranded costs related to generation
assets, Reliant Energy recorded Accelerated Depreciation of $194 million and
$104 million in 1998 and for the six months ended June 30, 1999, respectively,
for regulatory and financial reporting purposes. Accelerated Depreciation
expense was recorded in accordance with the Company's Transition Plan during
this period. Subsequent to June 30, 1999, Accelerated Depreciation expense could
no longer be recorded by the electric generation operations portion of Reliant
Energy HL&P for financial reporting purposes, as this portion of electric
operations is no longer accounted for under SFAS No. 71. During the six months
ended December 31, 1999 and during 2000 and 2001, $179 million, $385 million and
$264 million of Accelerated Depreciation was recorded for regulatory reporting
purposes, reducing the regulatory book value of Reliant Energy HL&P's electric
generation assets.
The Texas Utility Commission issued a final order on October 3, 2001
(October 3, 2001 Order) that established the transmission and distribution
utility rates that became effective January 2002. In this Order, the Texas
Utility Commission found that Reliant Energy HL&P had overmitigated its stranded
costs by redirecting transmission and distribution depreciation and by
accelerating depreciation of generation assets as provided under the Transition
Plan and Texas Electric Restructuring Law. As a result of the October 3, 2001
Order, Reliant Energy HL&P was required to reverse the $841 million embedded
regulatory asset related to Redirected Depreciation, thereby reducing the net
book value of transmission and distribution assets. Reliant Energy HL&P was
required to record a regulatory liability of $1.1 billion related to Accelerated
Depreciation. The October 3, 2001 Order requires this amount to be refunded
through excess mitigation credits to certain retail electric customers during a
seven year period beginning in January 2002. On appeal, a Texas District court
upheld the Texas Utility Commission's order. An appeal may be taken to a Texas
Court of Appeal, but no further appeal has yet been filed.
As of December 31, 2001, in contemplation of the True-up Proceeding,
Reliant Energy HL&P has recorded a regulatory asset of $2.0 billion representing
the estimated recovery of previously incurred stranded costs, which includes a
regulatory liability of $1.1 billion plus the reversal of previously recorded
Redirected Depreciation. This estimated recovery is based upon current
projections of the market value of the Reliant Energy HL&P electric generation
assets to be covered by the True-up Proceeding calculations. Because generally
accepted accounting principles require the Company to estimate fair market
values in advance of the final reconciliation, the financial impacts of the
Texas Electric Restructuring Law with respect to the final determination of
stranded costs in 2004 are subject to material changes. Factors affecting such
changes may include estimation risk, uncertainty of future energy and commodity
prices and the economic lives of the plants. If events were to occur that made
the recovery of some of the remaining generation related regulatory assets no
longer probable, the Company would write off the remaining balance of such
assets as a charge against earnings. For additional discussion of potential
future impairment of the assets of the Company's Texas generation business, see
Note 2(e).
Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71,
effective July 1, 1999, allowance for funds used during construction is no
longer accrued on generation related construction projects. Instead, interest is
being capitalized on these projects in accordance with SFAS No. 34,
"Capitalization of Interest Cost."
58
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred
the premiums and expenses that arose when long-term debt was redeemed and
amortized these costs over the life of the new debt. If no new debt was issued,
these costs would be amortized over the remaining original life of the retired
debt. Effective July 1, 1999, costs resulting from the retirement of debt
attributable to the generation operations of Reliant Energy HL&P will be
recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt," unless these costs will be recovered through regulated
cash flows. In that case, these costs will be deferred and recorded as a
regulatory asset by the entity through which the source of the regulated cash
flows will be derived.
(b) BUSINESS SEPARATION PLAN
Restructuring of Regulated Entities and Distribution of Reliant Resources
Stock. Pursuant to the Business Separation Plan, subject to receipt of an order
from the Securities and Exchange Commission (SEC) described below, Reliant
Energy will become a subsidiary of a new holding company, CenterPoint Energy,
which initially will own the Company's (a) electric transmission and
distribution operations, (b) natural gas distribution businesses, (c) electric
generating assets in Texas that were formerly operated by Reliant Energy HL&P,
(d) interstate pipelines, gas gathering and pipeline services operations, (e)
interests in energy companies in Latin America (see Note 19) and (f) interests
in Reliant Resources. In these Notes, references to Reliant Energy in connection
with events occurring or the performance of agreements after the Restructuring
generally refer to CenterPoint Energy.
Upon becoming a subsidiary of CenterPoint Energy, Reliant Energy will
transfer the stock of its principal operating subsidiaries to a subsidiary of
CenterPoint Energy and will transfer its electric generating assets in Texas
that were formerly operated by Reliant Energy HL&P to Texas Genco. In January
2004, Reliant Resources will have the right to exercise an option to acquire
Texas Genco, as further discussed below. As a result of the stock and asset
transfers described above, Reliant Energy will become solely a transmission and
distribution utility, with its other businesses becoming indirect subsidiaries
of CenterPoint Energy, which will assume all of Reliant Energy's debt other than
its first mortgage bonds. The indebtedness of certain wholly owned financing
subsidiaries of Reliant Energy is expected to be refinanced by the regulated
holding company by the end of 2002.
The Company anticipates that, upon completion of the Restructuring and
subject to approval by the Company's board of directors, market and other
conditions, CenterPoint Energy will distribute all of the stock it owns in
Reliant Resources to CenterPoint Energy's shareholders, affecting the separation
of its operations into two publicly traded corporations. The Company has
obtained a private letter ruling from the IRS providing for the tax-free
treatment of the Distribution that is predicated on the completion of the
Distribution by April 30, 2002. The Company has requested an extension of this
deadline. While there can be no assurance that the Company will receive the
extension, the Company anticipates that it will receive an extension that allows
it to proceed with the Distribution after April 30, 2002.
Reliant Energy has made and will continue to make internal asset and stock
transfers intended to allocate the assets and liabilities of Reliant Energy in
accordance with regulatory requirements and as contemplated by the Business
Separation Plan. Forms of each of the intercompany agreements described below
were prepared and entered into by Reliant Energy and Reliant Resources prior to
the Offering.
The Restructuring as currently planned cannot be completed unless and until
the SEC issues an order granting the required approvals under the Public Utility
Holding Company Act of 1935 (1935 Act). While the Company believes such an order
will be received, and that both the Restructuring and Distribution will be
completed during the summer of 2002, there can be no assurances that such will
be the case. The Restructuring has been designed to enable the Company to meet
all of the requirements of the Texas Electric Restructuring Law. The Company has
not formulated an alternative restructuring plan that could be implemented were
the SEC to refuse to grant the requested approvals for CenterPoint Energy.
59
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Agreements Related to Texas Generating Assets. Pursuant to the Business
Separation Plan, Reliant Energy expects to cause Texas Genco to conduct an
initial public offering of approximately 20% of its capital stock by the end of
2002. If the initial public offering is not conducted, Reliant Energy may
distribute approximately 20% of Texas Genco's capital stock to its stockholders
in a transaction taxable both to it and its stockholders as part of the
valuation of stranded costs. In connection with the separation of its
unregulated businesses from its regulated businesses, Reliant Energy granted
Reliant Resources an option, subject to the completion of the Distribution, to
purchase all of the shares of capital stock of Texas Genco that will be owned by
Reliant Energy after the initial public offering or distribution (Texas Genco
Option). The Texas Genco Option may be exercised between January 10, 2004 and
January 24, 2004. The per share exercise price under the option will be the
average daily closing price on the national exchange for publicly held shares of
common stock of Texas Genco for the 30 consecutive trading days with the highest
average closing price during the 120 trading days immediately preceding January
10, 2004, plus a control premium, up to a maximum of 10%, to the extent a
control premium is included in the valuation determination made by the Texas
Utility Commission relating to the market value of Texas Genco's common stock
equity. The exercise price is also subject to adjustment based on the difference
between the cash dividends paid during the period there is a public ownership
interest in Texas Genco and Texas Genco's earnings during that period. Reliant
Resources has agreed that if it exercises the Texas Genco Option and purchases
the shares of Texas Genco common stock, Reliant Resources will also purchase all
notes and other receivables from Texas Genco then held by Reliant Energy, at
their principal amount plus accrued interest. Similarly, if Texas Genco holds
notes or receivables from the Company, Reliant Resources will assume those
obligations in exchange for a payment to Reliant Resources by the Company of an
amount equal to the principal plus accrued interest.
Exercise of the Texas Genco Option by Reliant Resources will be subject to
various regulatory approvals, including Hart-Scott-Rodino antitrust clearance
and United States Nuclear Regulatory Commission (NRC) license transfer approval.
The option will be exercisable only if Reliant Energy or CenterPoint Energy
distributes all of the shares of Reliant Resources common stock it owns to its
shareholders.
At the time of the Restructuring, Texas Genco will become the beneficiary
of the decommissioning trust that has been established to provide funding for
decontamination and decommissioning of a nuclear electric generation station in
which Reliant Energy owns a 30.8% interest (see Note 6). The master separation
agreement provides that Reliant Energy will collect through rates or other
authorized charges to its electric utility customers amounts designated for
funding the decommissioning trust, and will pay the amounts to Texas Genco.
Texas Genco will in turn be required to deposit these amounts received from
Reliant Energy into the decommissioning trust. Upon decommissioning of the
facility, in the event funds from the trust are inadequate, Reliant Energy or
its successor will be required to collect through rates or other authorized
charges to customers as contemplated by the Texas Utilities Code all additional
amounts required to fund Texas Genco's obligations relating to the
decommissioning of the facility. Following the completion of the
decommissioning, if surplus funds remain in the decommissioning trust, the
excess will be refunded to Reliant Energy's or its successor's ratepayers.
(c) RELIANT ENERGY HL&P REGULATORY FILINGS
As of December 31, 2000 and 2001, Reliant Energy HL&P was under-collected
on fuel recovery by $558 million and $200 million, respectively. In two separate
filings with the Texas Utility Commission in 2000, Reliant Energy HL&P received
approval to implement fuel surcharges to collect the under-recovery of fuel
expenses, as well as to adjust the fuel factor to compensate for significant
increases in the price of natural gas. For additional information regarding this
matter, see Note 2(f).
On March 15, 2001, Reliant Energy HL&P filed an application with the Texas
Utility Commission to revise its fuel factor and address its undercollected fuel
costs of $389 million, which was the accumulated amount from September 2000
through February 2001, plus estimates for March and April 2001. Reliant
60
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Energy HL&P requested to revise its fixed fuel factor to be implemented with the
May 2001 billing cycle and proposed to defer the collection of the $389 million
until the 2004 stranded costs True-up Proceeding. On April 16, 2001, the Texas
Utility Commission issued an order approving interim rates effective with the
May 2001 billing cycle.
On June 21, 2001, Reliant Energy HL&P filed an application with the Texas
Utility Commission to terminate the interim factor and return to the prior fuel
factor due to the forecasted decline in natural gas prices. On July 20, 2001,
the Texas Utility Commission issued an order of dismissal approving Reliant
Energy HL&P's request that the interim rates approved on April 16, 2001,
effective with Reliant Energy HL&P's May 2001 billing month, be terminated and
Reliant Energy HL&P prospectively bill its customers using the prior fuel factor
established in a previous order beginning with Reliant Energy HL&P's August
billing month. The Texas Utility Commission also granted Reliant Energy HL&P a
good cause exception in that Reliant Energy HL&P will not be required to refund
amounts collected through the interim rates. Reliant Energy HL&P did not waive
its right to collect any final fuel balance. The final fuel balance is subject
to review, and the amount to be included in the 2004 stranded cost true-up will
be determined during the final fuel reconciliation. The Texas Utility Commission
currently has scheduled Reliant Energy HL&P to file its final fuel
reconciliation in July 2002.
(d) ARKLA RATE CASE
On November 21, 2001, Arkla filed a rate case (Docket 01-243-U) with the
Arkansas Public Service Commission seeking an increase in rates for its Arkansas
customers of approximately $47 million on an annual basis. Arkla's last rate
increase was authorized in 1995. In the rate filing, Arkla maintains that its
rate base has grown by $183 million, and its operating expenses have increased
from $93 million to $106 million on an annual basis and, therefore, Arkla's
current rates for service to Arkansas customers do not provide a reasonable
opportunity for Arkla to cover its operating costs and earn a fair return on its
investment. A decision in the case is expected by the fourth quarter of 2002.
(5) DERIVATIVE FINANCIAL INSTRUMENTS
Effective January 1, 2001, the Company adopted SFAS No. 133, which
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. This statement requires that derivatives be recognized at
fair value in the balance sheet and that changes in fair value be recognized
either currently in earnings or deferred as a component of other comprehensive
income (loss), depending on the intended use of the derivative, its resulting
designation and its effectiveness. If certain conditions are met, an entity may
designate a derivative instrument as hedging (a) the exposure to changes in the
fair value of an asset or liability (Fair Value Hedge), (b) the exposure to
variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign
currency exposure of a net investment in a foreign operation. For a derivative
not designated as a hedging instrument, the gain or loss is recognized in
earnings in the period it occurs.
Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax
increase in net income of $61 million and a cumulative after-tax increase in
accumulated other comprehensive loss of $422 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by approximately $627 million, $67 million, $778 million, and $277
million, respectively, in the Company's Consolidated Balance Sheets. During the
year ended December 31, 2001, $165 million of the initial after-tax transition
adjustment recognized in other comprehensive income was recognized in net
income.
The application of SFAS No. 133 is still evolving as the FASB clears issues
previously submitted to the Derivatives Implementation Group for consideration.
During the second quarter of 2001, an issue that applies exclusively to the
electric industry and allows the normal purchases and normal sales exception for
option-type contracts if certain criteria are met was approved by the FASB with
an effective date of July 1, 2001. The
61
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adoption of this cleared guidance had no impact on the Company's results of
operations. Certain criteria of this previously approved guidance were revised
in October and December 2001 and became effective on April 1, 2002. The Company
is currently in the process of determining the effect of adoption of the revised
guidance.
During the third quarter of 2001, the FASB cleared an issue related to
application of the normal purchases and normal sales exception to contracts that
combine forward and purchased option contracts. The effective date of this
guidance is April 1, 2002, and the Company is currently assessing the impact of
this cleared issue and does not believe it will have a material impact on the
Company's consolidated financial statements.
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
the Company's consolidated financial statements. The Company utilizes derivative
instruments such as futures, physical forward contracts, swaps and options
(Energy Derivatives) to mitigate the impact of changes in electricity, natural
gas and fuel prices on its operating results and cash flows. The Company
utilizes cross-currency swaps, forward contracts and options to hedge its net
investments in and cash flows of its foreign subsidiaries, interest rate swaps
to mitigate the impact of changes in interest rates and other financial
instruments to manage various other market risks.
Trading and marketing operations often involve risk associated with
managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. The Company routinely
enters into Energy Derivatives to hedge purchase and sale commitments, fuel
requirements and inventories of natural gas, coal, electricity, crude oil and
products, emission allowances and other commodities and to minimize the risk of
market fluctuations in its trading, marketing, power origination and risk
management services operations.
Energy Derivatives primarily used by the Company are described below:
- Future contracts are exchange-traded standardized commitments to purchase
or sell an energy commodity or financial instrument, or to make a cash
settlement, at a specific price and future date.
- Physical forward contracts are commitments to purchase or sell energy
commodities in the future.
- Swap agreements require payments to or from counterparties based upon the
differential between a fixed price and variable index price (fixed price
swap) or two variable index prices (variable price swap) for a
predetermined contractual notional amount. The respective index may be an
exchange quotation or an industry pricing publication.
- Option contracts convey the right to buy or sell an energy commodity,
financial instrument at a predetermined price or settlement of the
differential between a fixed price and a variable index price or two
variable index prices.
(a) ENERGY TRADING, MARKETING, POWER ORIGINATION AND PRICE RISK MANAGEMENT
ACTIVITIES
The Company offers energy price risk management services primarily related
to natural gas, electric power and other energy related commodities. These
activities also include the establishing of open positions in the energy
markets, primarily on a short-term basis, and transactions intended to optimize
the Company's power generation portfolio, but which do not qualify for hedge
accounting. The Company provides these services by utilizing a variety of
derivative instruments (Trading Energy Derivatives).
The Company applies mark-to-market accounting for all of its energy
trading, marketing, power origination and price risk management services
operations in North America and Europe, as well as to retail contracted sales to
large commercial, industrial and institutional customers. Accordingly, these
Trading Energy Derivatives are recorded at fair value with net realized and
unrealized gains (losses) recorded as a
62
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
component of revenues. The recognized, unrealized balances are recorded as
trading and marketing assets/liabilities.
<Table>
<Caption>
FAIR VALUE
--------------------
ASSETS LIABILITIES
------ -----------
(IN MILLIONS)
December 31, 2000
Natural gas............................................... $3,823 $3,818
Electricity............................................... 974 946
Oil and other............................................. 39 39
------ ------
$4,836 $4,803
====== ======
December 31, 2001
Natural gas............................................... $1,389 $1,303
Electricity............................................... 648 517
Oil and other............................................. 21 20
------ ------
$2,058 $1,840
====== ======
</Table>
All of the fair values shown in the table above at December 31, 2000 and
2001 have been recognized in income. The fair values as of December 31, 2000 and
2001, are estimated using quoted prices where available, other valuation
techniques when market data is not available, for example in illiquid markets,
and other factors such as time value and volatility factor for the underlying
commitment. The Company's alternative pricing methodologies include, but are not
limited to, extrapolation of forward pricing curves using historically reported
data from illiquid pricing points. These same pricing techniques are used to
evaluate a contract prior to taking the position.
The fair values in the above table are subject to significant changes based
on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, power origination, marketing and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant estimates include natural gas and power forward market prices,
volatility and credit risk. For the contracted retail electric sales to large
commercial, industrial and institutional customers, significant variables
affecting contract values also include the variability in electricity
consumption patterns due to weather and operational uncertainties (within
contract parameters). Market prices assume a normal functioning market with an
adequate number of buyers and sellers providing market liquidity. Insufficient
market liquidity could significantly affect the values that could be obtained
for these contracts, as well as the costs at which these contracts could be
hedged.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum term of the trading portfolio is 17 years. These
maximum and average terms are not indicative of likely future cash flows, as
these positions may be changed by new transactions in the trading portfolio at
any time in response to changing market conditions, market liquidity and the
Company's risk management portfolio needs and strategies. Terms regarding cash
settlements of these contracts vary with respect to the actual timing of cash
receipts and payments.
(b) NON-TRADING ACTIVITIES
Cash Flow Hedges. To reduce the risk from market fluctuations in revenues
and the resulting cash flows derived from the sale of electric power, natural
gas and other commodities, the Company may enter into Energy Derivatives in
order to hedge exposure to variability in cash flows (Non-trading Energy
Derivatives).
63
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Non-trading Energy Derivative portfolios are managed to complement the
physical transaction portfolio, reducing overall risks within authorized limits.
The Company applies hedge accounting for its Non-trading Energy Derivatives
utilized in non-trading activities only if there is a high correlation between
price movements in the derivative and the item designated as being hedged. This
correlation, a measure of hedge effectiveness, is measured both at the inception
of the hedge and on an ongoing basis, with an acceptable level of correlation of
at least 80% to 120% for hedge designation. If and when correlation ceases to
exist at an acceptable level, hedge accounting ceases and mark-to-market
accounting is applied. During 2001, the amount of hedge ineffectiveness
recognized in earnings from derivatives that are designated and qualify as Cash
Flow Hedges was a gain of $8 million. No component of the derivative
instruments' gain or loss was excluded from the assessment of effectiveness. If
it becomes probable that an anticipated transaction will not occur, the Company
realizes in net income the deferred gains and losses recognized in accumulated
other comprehensive income (loss). During the year ended December 31, 2001,
there was a $3.6 million deferred loss recognized in earnings as a result of the
discontinuance of cash flow hedges because it was no longer probable that the
forecasted transaction would occur due to credit problems of a customer. Once
the anticipated transaction occurs, the accumulated deferred gain or loss
recognized in accumulated other comprehensive income (loss) is reclassified and
included in the Company's Statements of Consolidated Income under the captions
(a) fuel expenses, in the case of natural gas purchase transactions, (b)
purchased power, in the case of electric power purchase transactions and (c)
revenues, in the case of electric power and natural gas sales transactions and
financial electric power or natural gas derivatives. Cash flows resulting from
these transactions in Non-trading Energy Derivatives are included in the
Statements of Consolidated Cash Flows in the same category as the item being
hedged. As of December 31, 2001, the Company's current non-trading derivative
assets and liabilities and corresponding amounts in accumulated other
comprehensive loss were expected to be reclassified into net income during the
next twelve months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows for forecasted transactions excluding the
payment of variable interest on existing financial instruments is eleven years.
In addition, as of December 31, 2001, the European Energy business segment
had entered into transactions to purchase $271 million at fixed exchange rates
in order to hedge future fuel purchases payable in U.S. dollars.
Interest Rate Swaps. During 2001, the Company entered into interest rate
swaps with an aggregate notional amount of $1.8 billion to fix the interest rate
applicable to floating rate short-term debt and interest rate swaps with a
notional amount of $425 million to fix the interest rate applicable to floating
rate long-term debt. At December 31, 2001, $225 million of the swaps relating to
long-term debt had expired. The swaps relating to short-term debt do not qualify
as cash flow hedges under SFAS No. 133, and are marked to market on the
Consolidated Balance Sheets with changes reflected in interest expense in the
Statements of Consolidated Income. The swaps relating to long-term debt qualify
for hedge accounting under SFAS No. 133 and the periodic settlements are
recognized as an adjustment to interest expense in the Statements of
Consolidated Income over the term of the swap agreement. During 2001, the
Company entered into forward-starting interest rate swaps having an aggregate
notional amount of $500 million to hedge the interest rate on a portion of a
future offering of five-year notes. These swaps qualify as cash flow hedges
under SFAS No. 133. Should the expected issuance of the debt no longer be
probable, any deferred amount will be recognized immediately into income. The
maximum length of time the Company is hedging its exposure to the payment of
variable interest rates is four years.
Hedge of the Foreign Currency Exposure of Net Investment in Foreign
Subsidiaries. The Company has substantially hedged the foreign currency
exposure of its net investment in its European subsidiaries through a
combination of Euro-denominated borrowings, foreign currency swaps and foreign
currency forward contracts
64
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to reduce the Company's exposure to changes in foreign currency rates. During
the normal course of business, the Company reviews its currency hedging
strategies and determines the hedging approach deemed appropriate based upon the
circumstances of each situation.
The Company records the changes in the value of the foreign currency
hedging instruments and Euro-denominated borrowings as foreign currency
translation adjustments included as a component of accumulated other
comprehensive loss. The effectiveness of the hedging instruments can be measured
by the net change in foreign currency translation adjustments attributed to the
Company's net investment in its European subsidiaries. These amounts generally
offset amounts recorded in stockholders' equity as adjustments resulting from
translation of the hedged investment into U.S. dollars. During 2001, the
derivative and non-derivative instruments designated as hedging the net
investment in the Company's European subsidiaries resulted in a gain of $31
million, which is included in the balance of the cumulative translation
adjustment.
Other Derivatives. In December 2000, the Dutch parliament adopted
legislation allocating to the Dutch generation sector, including REPGB,
financial responsibility for various stranded costs contracts and other
liabilities. The legislation became effective in all material respects on
January 1, 2001. In particular, the legislation allocated to the Dutch
generation sectors, including REPGB, financial responsibility to purchase
electricity and gas under gas supply and electricity contracts. These contracts
are derivatives pursuant to SFAS No. 133. As of December 31, 2001, the Company
had recognized $369 million in short-term and long-term non-trading derivative
liabilities for REPGB's portion of these stranded costs contracts. Future
changes in the valuation of these stranded cost import contracts which remain an
obligation of REPGB will be recorded as adjustments to the Company's Statements
of Consolidated Income. The valuation of the contracts could be affected by,
among other things, changes in the price of electric power, coal, low sulfur
fuel oil and the value of the United States dollar and British pound relative to
the Euro. For additional information regarding REPGB's stranded costs and the
related indemnification by former shareholders of these stranded costs during
2001, see Note 14(h).
During 2001, Reliant Resources entered into two structured transactions
which were recorded on the Consolidated Balance Sheets in non-trading derivative
assets and liabilities involving a series of forward contracts to buy and sell
an energy commodity in 2001 and to buy and sell an energy commodity in 2002 or
2003. The change in fair value of these derivative assets and liabilities must
be recorded in the Statements of Consolidated Income for each reporting period.
During 2001, $117 million of net non-trading derivative liabilities were settled
related to these transactions, and a $1 million pre-tax unrealized gain was
recognized. As of December 31, 2001, Reliant Resources has recognized $221
million of non-trading derivative assets and $103 million of non-trading
derivative liabilities related to these transactions.
(c) CREDIT RISKS
In addition to the risk associated with price movements, credit risk is
inherent in the Company's risk management activities and hedging activities.
Credit risk relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. The Company has off-balance sheet
risk to the extent that the counterparties to these transactions may fail to
perform as required by the terms of each contract. The Company enters into
derivative instruments primarily with counterparties having at least a minimum
investment grade credit rating (i.e. a minimum credit rating for such entity's
senior unsecured debt of BBB- for Standard & Poor's and Fitch or Baa3 for
Moody's). In addition, the Company seeks to enter into netting agreements that
permit it to offset receivables and payables with a given counterparty. The
Company also attempts to enter into agreements that enable the Company to obtain
collateral from a counterparty or to terminate upon the occurrence of
credit-related events. For long-term arrangements, the Company periodically
reviews the financial condition of these counterparties in addition to
monitoring the effectiveness of these financial contracts in achieving the
Company's objectives. If the counterparties to these arrangements fail to
perform, the Company would seek to compel performance at law or otherwise obtain
compensatory damages.
65
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company might be forced to acquire alternative hedging arrangements or be
required to replace the underlying commitment at then-current market prices. In
this event, the Company might incur additional losses to the extent of amounts,
if any, already paid to the counterparties. For information regarding the
provision related to energy sales in California, see Note 14(g). For information
regarding the net provision recorded in 2001 related to energy sales to Enron,
see Note 21.
The following tables show the composition of the trading and marketing
assets of the Company as of December 31, 2000 and 2001 and the non-trading
derivative assets as of December 31, 2001.
<Table>
<Caption>
DECEMBER 31, 2000 DECEMBER 31, 2001
------------------- -------------------
INVESTMENT INVESTMENT
TRADING AND MARKETING ASSETS GRADE(2) TOTAL GRADE(2) TOTAL
- ---------------------------- ---------- ------ ---------- ------
(IN MILLIONS)
Energy marketers............................... $2,291 $2,481 $ 683 $ 757
Financial institutions......................... 1,099 1,228 495 495
Gas and electric utilities..................... 472 542 538 544
Oil and gas producers.......................... 474 566 135 176
Commercial, industrial and institutional
customers.................................... 73 85 119 184
------ ------ ------ ------
Total........................................ $4,409 4,902 $1,970 2,156
====== ======
Credit and other reserves...................... (66) (98)
------ ------
Trading and marketing assets................... $4,836 $2,058
====== ======
</Table>
<Table>
<Caption>
DECEMBER 31, 2001
-------------------
INVESTMENT
NON-TRADING DERIVATIVE ASSETS GRADE(1)(2) TOTAL
- ----------------------------- ----------- -----
(IN MILLIONS)
Energy marketers............................................ $371 $408
Financial institutions...................................... 76 76
Gas and electric utilities.................................. 89 90
Oil and gas producers....................................... 8 76
Commercial, industrial and institutional customers.......... 7 8
Others...................................................... 5 14
---- ----
Total..................................................... $556 672
==== ----
Credit and other reserves................................... (16)
----
Non-trading derivative assets............................... $656
====
</Table>
- ---------------
(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.
(2) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions, and collateral,
to create a synthetic credit rating.
(d) TRADING AND NON-TRADING -- GENERAL POLICY
The Company has established a Risk Oversight Committee comprised of
corporate and business segment officers that oversees all commodity price,
foreign currency and credit risk activities, including the Company's trading,
marketing, power origination, risk management services and hedging activities.
The committee's
66
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
duties are to approve the Company's commodity risk policies, allocate risk
capital within limits established by the Company's board of directors, approve
trading of new products and commodities, monitor risk positions and monitor
compliance with the Company's risk management policies and procedures and
trading limits established by the Company's board of directors.
The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
(8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES
(a) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES
On July 6, 1999, the Company converted its 11 million shares of Time Warner
Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of
Time Warner common stock (TW Common). Prior to the conversion, the Company's
investment in the TW Preferred was accounted for under the cost method at a
value of $990 million in the Company's Consolidated Balance Sheets. The TW
Preferred which was redeemable after July 6, 2000, had an aggregate liquidation
preference of $100 per share (plus accrued and unpaid dividends), was entitled
to annual dividends of $3.75 per share until July 6, 1999 and was convertible by
the Company. The Company recorded pre-tax dividend income with respect to the TW
Preferred of $21 million in 1999 prior to the conversion. Effective on the
conversion date, the shares of TW Common were classified as trading securities
under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4
billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the
fair value of the Company's investment in Time Warner securities. Unrealized
gains and losses resulting from changes in the market value of the TW Common
(now AOL TW Common) are recorded in the Company's Statements of Consolidated
Income.
(b) ACES
In July 1997, in order to monetize a portion of the cash value of its
investment in TW Preferred, the Company issued 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES) having an original principal amount
of $1.052 billion and maturing July 1, 2000. The market value of ACES was
indexed to the market value of TW Common. On the July 1, 2000 maturity date, the
Company tendered 37.9 million shares of TW Common to fully settle its
obligations in connection with its unsecured 7% ACES having a value of $2.9
billion.
(c) ZENS
On September 21, 1999, the Company issued approximately 17.2 million of its
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an
original principal amount of $1.0 billion. The original principal amount per
ZENS will increase each quarter to the extent that the sum of the quarterly cash
dividends and the interest paid during a quarter on the reference shares
attributable to one ZENS is less than $.045, so that the annual yield to
investors from the date the Company issued the ZENS to the date of computation
of the contingent principal amount is not less than 2.309%. At December 31,
2001, the principal amount of the ZENS had increased $3 million as the reference
shares no longer pay dividends. At maturity the holders of the ZENS will receive
in cash the higher of the original principal amount of the ZENS (subject to
adjustment as discussed above) or an amount based on the then-current market
value of AOL TW
67
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Common, or other securities distributed with respect to AOL TW Common (1.5
shares of AOL TW Common and such other securities, if any, are referred to as
reference shares). Each ZENS has an original principal amount of $58.25, and is
exchangeable at any time at the option of the holder for cash equal to 95% (100%
in some cases) of the market value of the reference shares attributable to one
ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the
amount of any quarterly cash dividends paid in respect of the quarterly interest
period on the reference shares attributable to each ZENS. Subject to some
conditions, the Company has the right to defer interest payments from time to
time on the ZENS for up to 20 consecutive quarterly periods. As of December 31,
2001, no interest payments on the ZENS had been deferred.
The Company used $537 million of the net proceeds from the offering of the
ZENS to purchase 9.2 million shares of TW Common (now 13.8 million shares of AOL
TW Common), which are classified as trading securities under SFAS No. 115. Prior
to the purchase of additional shares of TW Common on September 21, 1999, the
Company owned approximately 8 million shares of TW Common (now 12 million shares
of AOL TW Common). The Company now holds 25.8 million shares of AOL TW Common
that are expected to be held to facilitate the Company's ability to meet its
obligation under the ZENS.
Prior to January 1, 2001, an increase above $58.25 (subject to some
adjustments) in the market value per share of TW Common resulted in an increase
in the Company's liability for the ZENS. However, as the market value per share
of TW Common declined below $58.25 (subject to some adjustments), the liability
for the ZENS did not decline below the original principal amount. The market
value per share of TW Common was $52.24 as of December 31, 2000 and the market
value per share of AOL TW Common was $32.10 as of December 31, 2001. Upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was
bifurcated into a debt component and a derivative component (the holder's option
to receive the appreciated value of AOL TW Common at maturity). The derivative
component was valued at fair value and determined the initial carrying value
assigned to the debt component ($121 million) as the difference between the
original principal amount of the ZENS ($1.0 billion) and the fair value of the
derivative component at issuance ($879 million). Effective January 1, 2001 the
debt component was recorded at its accreted amount of $122 million and the
derivative component is recorded at its current fair value of $788 million, as a
current liability, resulting in a transition adjustment pre-tax gain of $90
million ($58 million net of tax). The transition adjustment gain was reported in
the first quarter of 2001 as the effect of a change in accounting principle.
Subsequently, the debt component will accrete through interest charges at 17.5%
up to the minimum amount payable upon maturity of the ZENS in 2029,
approximately $1.1 billion, and changes in the fair value of the derivative
component will be recorded in the Company's Statements of Consolidated Income.
During 2001, the Company recorded a $70 million loss on the Company's investment
in AOL TW Common. During 2001, the Company recorded a $58 million gain
associated with the fair value of the derivative component of the ZENS
obligation. Changes in the fair value of the AOL TW Common held by the Company
are expected to substantially offset changes in the fair value of the derivative
component of the ZENS.
68
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth summarized financial information regarding
the Company's investment in AOL TW securities and the Company's ACES and ZENS
obligations (in millions).
<Table>
<Caption>
DEBT DERIVATIVE
AOL TW COMPONENT OF COMPONENT
INVESTMENT ACES ZENS OF ZENS
---------- ------- ------------ ----------
Balance at December 31, 1998............. $ 990 $ 2,350 $ -- $ --
Issuance of indexed debt securities...... -- -- 1,000 --
Purchase of TW Common.................... 537 -- -- --
Loss on indexed debt securities.......... -- 388 241 --
Gain on TW Common........................ 2,452 -- -- --
------- ------- ------ ----
Balance at December 31, 1999............. 3,979 2,738 1,241 --
Loss (gain) on indexed debt securities... -- 139 (241) --
Loss on TW Common........................ (205) -- -- --
Settlement of ACES....................... (2,877) (2,877) -- --
------- ------- ------ ----
Balance at December 31, 2000............. 897 -- 1,000 --
Transition adjustment from adoption of
SFAS No. 133........................... -- -- (90) --
Bifurcation of ZENS obligation........... -- -- (788) 788
Accretion of debt component of ZENS...... -- -- 1 --
Gain on indexed debt securities.......... -- -- -- (58)
Loss on AOL TW Common.................... (70) -- -- --
------- ------- ------ ----
Balance at December 31, 2001............. $ 827 $ -- $ 123 $730
======= ======= ====== ====
</Table>
69
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(10) LONG-TERM DEBT AND SHORT-TERM BORROWINGS
<Table>
<Caption>
DECEMBER 31, 2000 DECEMBER 31, 2001
---------------------- ----------------------
LONG- LONG-
TERM CURRENT(1) TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Short-term borrowings:
Commercial paper.......................................... $3,675 $2,502
Lines of credit........................................... 853 290
Receivables facility...................................... 350 346
Other(2).................................................. 126 297
------ ------
Total short-term borrowings................................. $5,004 $3,435
------ ------
Long-term debt:
Reliant Energy
ZENS(3)................................................... $ -- $1,000 $ -- $ 123
Debentures 7.88% to 9.38% due 2002........................ 100 250 -- 100
First mortgage bonds 4.90% to 9.15% due 2002 to 2027...... 1,261 -- 1,161 100
Pollution control bonds 4.70% to 5.95% due 2011 to 2030... 1,046 -- 1,046 --
Series 2001-1 Transition Bonds 3.84% to 5.63% due 2002 to
2013.................................................... -- -- 736 13
Other..................................................... 12 1 11 1
Financing Subsidiaries (directly or indirectly owned by
Reliant Energy)
Debentures 7.40% due 2002................................. 300 225 -- 300
Reliant Energy Power Generation, Inc.
Notes payable various market rates due 2002 to 2024....... 260 -- 295 2
REPGB(2)
Debentures 6.00% to 8.94% due 2002 to 2006................ 66 1 38 22
Reliant Energy Capital Europe(2)
Notes payable various market rates due 2003............... 565 -- 534 --
RERC Corp.(4)
Convertible debentures 6.00% due 2012..................... 93 -- 82 --
Debentures 6.38% to 8.90% due 2003 to 2011................ 1,285 -- 1,833 --
Notes payable 8.77% to 9.23% paid 2001.................... -- 146 -- --
Unamortized discount and premium............................ 8 -- 6 --
------ ------ ------ ------
Total long-term debt.................................... 4,996 1,623 5,742 661
------ ------ ------ ------
Total borrowings........................................ $4,996 $6,627 $5,742 $4,096
====== ====== ====== ======
</Table>
- ---------------
(1) Includes amounts due or exchangeable within one year of the date noted.
(2) Includes borrowings at December 31, 2000 and 2001 which are denominated in
Euros. As of December 31, 2000 and 2001, the assumed exchange rate was 1.06
Euros and 1.12 Euros per U.S. dollar, respectively.
70
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(3) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS
obligation was bifurcated into a debt component and an embedded derivative
component. For additional information regarding ZENS, see Note 8(b). As ZENS
are exchangeable for cash at any time at the option of the holders, these
notes are classified as a current portion of long-term debt.
(4) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in long term debt is additional
unamortized premium related to fair value adjustments of long-term debt of
$12 million and $9 million at December 31, 2000 and 2001, respectively,
which is being amortized over the respective remaining term of the related
long-term debt.
(b) LONG-TERM DEBT
Maturities. The Company's maturities of long-term debt and sinking fund
requirements, excluding the ZENS obligation, are $538 million in 2002, $1.2
billion in 2003, $90 million in 2004, $390 million in 2005 and $218 million in
2006. The 2002 and 2003 amounts are net of sinking fund payments that can be
satisfied with bonds that had been acquired and retired as of December 31, 2001.
Liens. At December 31, 2001, substantially all physical assets used in the
conduct of the business and operations of the Electric Operations business
segment are subject to liens securing the First Mortgage Bonds. After the
Restructuring, only the assets of the transmission and distribution utility are
expected to be subject to liens securing the First Mortgage Bonds. Sinking fund
requirements on the First Mortgage Bonds may be satisfied by certification of
property additions at 100% of the requirements as defined by the Mortgage and
Deed of Trust. Sinking or improvement/replacement fund requirements for 1999,
2000 and 2001 have been satisfied by certification of property additions. The
replacement fund requirement to be satisfied in 2002 is $334 million.
RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million
of unsecured notes that bear interest at 7.75% per year and mature in February
2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net
proceeds from the sale of the notes to pay a $400 million dividend to Reliant
Energy, and for general corporate purposes. Reliant Energy used the $400 million
proceeds from the dividend for general corporate purposes, including the
repayment of short-term borrowings.
Securitization. For a discussion of the securitization financing completed
in October 2001, see Note 4(a).
Purchase of Convertible Debentures. At December 31, 2000 and 2001, RERC
Corp. had issued and outstanding $98 million and $86 million, respectively,
aggregate principal amount ($93 million and $82 million, respectively, carrying
amount) of its 6% Convertible Subordinated Debentures due 2012 (Subordinated
Debentures). The holders of the Subordinated Debentures receive interest
quarterly and have the right at any time on or before the maturity date thereof
to convert each Subordinated Debenture into 0.65 shares of Reliant Energy common
stock and $14.24 in cash. After the Restructuring, each Subordinated Debenture
will be convertible into 0.65 shares of CenterPoint Energy common stock and
$14.24 in cash. After the Distribution, each Subordinated Debenture will be
convertible into an increased number of CenterPoint Energy shares based on a
formula as provided in the relevant indenture and $14.24 in cash. During 2001,
RERC Corp. purchased $11 million aggregate principal amount of its Subordinated
Debentures.
TERM Notes. RERC Corp.'s $500 million aggregate principal amount of 6 3/8%
Term Enhanced ReMarketable Securities (TERM Notes) provide an investment bank
with a call option, which gives it the right to have the TERM Notes redeemed
from the investors on November 1, 2003 and then remarketed if it chooses to
exercise the option. The TERM Notes are unsecured obligations of RERC Corp.
which bear interest at an annual rate of 6 3/8% through November 1, 2003. On
November 1, 2003, the holders of the TERM Notes are required to tender their
notes at 100% of their principal amount. The portion of the proceeds
attributable to the call option premium will be amortized over the stated term
of the securities. If the option is not exercised by the investment bank, RERC
Corp. will repurchase the TERM Notes at 100% of their principal amount on
November 1, 2003. If the option is exercised, the TERM Notes will be remarketed
on a date, selected by RERC Corp., within the 52-week period beginning November
1, 2003. During this period and prior to remarketing, the TERM Notes will bear
interest at rates, adjusted weekly, based on an index selected by RERC Corp. If
the TERM Notes are remarketed, the final maturity date of the TERM Notes will be
November 1, 2013, subject to adjustment, and the effective interest rate on the
remarketed TERM Notes will be 5.66% plus RERC Corp.'s applicable credit spread
at the time of such remarketing.
Extinguishments of Debt. During the second quarter of 2000, REPGB
negotiated the repurchase of $272 million aggregate principal amount of its
long-term debt for a total cost of $286 million, including $14 million in
expenses. The book value of the debt repurchased was $293 million, resulting in
an extraordinary gain on the early extinguishment of long-term debt of $7
million. Borrowings under a short-term
71
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
banking facility and proceeds from the sale of trading securities by REPGB were
used to finance the debt repurchase.
During 1999, the Company's regulated operations recorded losses from the
extinguishment of debt of $22 million. There were no losses recorded from the
early extinguishment of debt in 2000 and 2001. As these costs will be recovered
through regulated cash flows, these costs have been deferred and a regulatory
asset has been recorded. For further discussion regarding the accounting, see
Note 4(a).
(11) TRUST PREFERRED SECURITIES
In February 1997, two Delaware statutory business trusts created by Reliant
Energy (HL&P Capital Trust I and HL&P Capital Trust II) issued to the public (a)
$250 million aggregate amount of preferred securities and (b) $100 million
aggregate amount of capital securities, respectively. In February 1999, a
Delaware statutory business trust created by Reliant Energy (REI Trust I) issued
$375 million aggregate amount of preferred securities to the public. Reliant
Energy accounts for REI Trust I, HL&P Capital Trust I and HL&P Capital Trust II
as wholly owned consolidated subsidiaries. Each of the trusts used the proceeds
of the offerings to purchase junior subordinated debentures issued by Reliant
Energy having interest rates and maturity dates that correspond to the
distribution rates and the mandatory redemption dates for each series of
preferred securities or capital securities.
The junior subordinated debentures are the trusts' sole assets and their
entire operations. Reliant Energy considers its obligations under the Amended
and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where
applicable, Agreement as to Expenses and Liabilities, relating to each series of
preferred securities or capital securities, taken together, to constitute a full
and unconditional guarantee by Reliant Energy of each trust's obligations with
respect to the respective series of preferred securities or capital securities.
The preferred securities and capital securities are mandatorily redeemable
upon the repayment of the related series of junior subordinated debentures at
their stated maturity or earlier redemption. Subject to some limitations,
Reliant Energy has the option of deferring payments of interest on the junior
subordinated debentures. During any deferral or event of default, Reliant Energy
may not pay dividends on its capital stock. As of December 31, 2001, no interest
payments on the junior subordinated debentures had been deferred.
In June 1996, a Delaware statutory business trust created by RERC Corp.
(RERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. RERC Corp. accounts for RERC Trust as a wholly owned
consolidated subsidiary. RERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by RERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent RERC Trust's sole assets
and its entire operations. RERC Corp. considers its obligation under the Amended
and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to
the convertible preferred securities, taken together, to constitute a full and
unconditional guarantee by RERC Corp. of RERC Trust's obligations with respect
to the convertible preferred securities.
The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Reliant Energy common stock. During 2000 and 2001, convertible preferred
securities of $0.3 million and $0.04 million,
72
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
respectively, were converted. As of December 31, 2000 and 2001, $0.4 million
liquidation amount of convertible preferred securities were outstanding. Subject
to some limitations, RERC Corp. has the option of deferring payments of interest
on the convertible junior subordinated debentures. During any deferral or event
of default, RERC Corp. may not pay dividends on its common stock to Reliant
Energy. As of December 31, 2001, no interest payments on the convertible junior
subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of each series of the preferred securities,
convertible preferred securities or capital securities of the trusts and the
identity and similar terms of each related series of junior subordinated
debentures are as follows:
<Table>
<Caption>
AGGREGATE
LIQUIDATION
AMOUNTS AS OF MANDATORY
DECEMBER 31, DISTRIBUTION REDEMPTION
TRUST 2000 AND 2001 RATE/INTEREST RATE DATE/MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
- ----- ------------- ------------------ ------------------ ------------------------------
(IN MILLIONS)
REI Trust I............ $375 7.20% March 2048 7.20% Junior Subordinated
Debentures due 2048
HL&P Capital Trust I... $250 8.125% March 2046 8.125% Junior Subordinated
Deferrable Interest Debentures
Series A
HL&P Capital Trust $100 8.257% February 2037 8.257% Junior Subordinated
II................... Deferrable Interest Debentures
Series B
RERC Trust............. $ 1 6.25% June 2026 6.25% Convertible Junior
Subordinated Debentures due
2026
</Table>
(13) INCOME TAXES
The components of income before taxes are as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
1999 2000 2001
------- ----- -------
(IN MILLIONS)
United States............................................... $2,535 $578 $1,302
Foreign..................................................... 29 180 117
------ ---- ------
Income before income taxes................................ $2,564 $758 $1,419
====== ==== ======
</Table>
Tax Refunds. In 2000, the Company received refunds from the IRS totaling
$126 million in taxes and interest following audits of tax returns and refund
claims for Reliant Energy's 1985, 1986 and 1990 through 1995 tax years, and RERC
Corp.'s 1979 through 1993 tax years. The pre-tax income statement effect of $40
million ($26 million after-tax) was recorded in 2000 in other income in the
Company's Statements of Consolidated Income. Of the refunds, $26 million was
recorded as a reduction in goodwill. Reliant Energy's consolidated federal
income tax returns have been audited and settled through the 1996 tax year. All
of RERC Corp.'s consolidated federal income tax returns for tax years ending on
or prior to Reliant Energy's acquisition of RERC Corp. have been audited and
settled.
73
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(14) COMMITMENTS AND CONTINGENCIES
(a) COMMITMENTS AND GUARANTEES
The following information is presented separately for the Company's
regulated and unregulated businesses:
RELIANT ENERGY (TO BECOME CENTERPOINT ENERGY SUBSEQUENT TO THE RESTRUCTURING)
Capital and Environmental Commitments. Reliant Energy anticipates
investing up to $397 million in capital and other special project expenditures
between 2002 and 2006 for environmental compliance. Reliant Energy anticipates
expenditures to be as follows (in millions):
<Table>
2002........................................................ $234
2003........................................................ 132
2004........................................................ 28
2005........................................................ 3
2006........................................................ --
----
Total..................................................... $397
====
</Table>
Fuel and Purchased Power. Fuel commitments include several long-term coal,
lignite and natural gas contracts related to Texas power generation operations,
which have various quantity requirements and durations that are not classified
as non-trading derivatives assets and liabilities or trading and marketing
assets and liabilities in the Company's Consolidated Balance Sheets as of
December 31, 2001 as these contracts meet the SFAS No. 133 exception to be
classified as "normal purchases contracts" (see Note 5) or do not meet the
definition of a derivative. Minimum payment obligations for coal and
transportation agreements that extend through 2009 are approximately $199
million in 2002, $129 million in 2003, $133 million in 2004, $137 million in
2005 and $141 million in 2006. Purchase commitments related to lignite mining
and lease agreements, natural gas purchases and storage contracts, and purchased
power are not material to Reliant Energy's operations. Prior to January 1, 2002,
the Electric Operations business segment was allowed recovery of these costs
through rates for electric service. As of December 31, 2001, some of these
contracts are above market. Reliant Energy anticipates that stranded costs
associated with these obligations will be recoverable through the stranded cost
recovery mechanisms contained in the Texas Electric Restructuring Law. For
information regarding the Texas Electric Restructuring Law, see Note 4(a).
Reliant Energy's other long-term fuel supply commitments which have various
quantity requirements and durations are not considered material either
individually or in the aggregate to its results of operations or cash flows.
74
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RELIANT RESOURCES -- UNREGULATED BUSINESSES
As of December 31, 2001, the Wholesale Energy business segment had entered
into commitments associated with various non-rate regulated electric generating
projects, including commitments for the purchase of combustion turbines,
aggregating $440 million. In addition, the Wholesale Energy business segment has
options to purchase additional generating equipment for a total estimated cost
of $42 million for future generation projects. Reliant Resources is actively
attempting to remarket this equipment.
Reliant Resources is a party to several fuel supply contracts, commodity
transportation contracts, and purchase power and electric capacity contracts,
that have various quantity requirements and durations that are not classified as
non-trading derivatives assets and liabilities or trading and marketing assets
and liabilities in the Consolidated Balance Sheets as of December 31, 2001 as
these contracts meet the SFAS No. 133 exception to be classified as "normal
purchases contracts" (see Note 5) or do not meet the definition of a derivative.
The maximum duration of any of these commitments is 21 years. Minimum purchase
commitment obligations under these agreements are as follows for the next five
years, as of December 31, 2001 (in millions):
<Table>
<Caption>
PURCHASED POWER
AND ELECTRIC AND
TRANSPORTATION GAS CAPACITY
FUEL COMMITMENTS COMMITMENTS COMMITMENTS
---------------- -------------- ----------------
2002.................................... $105 $ 45 $315
2003.................................... 39 84 119
2004.................................... 45 101 61
2005.................................... 45 101 61
2006.................................... 45 101 61
---- ---- ----
Total................................. $279 $432 $617
==== ==== ====
</Table>
The maximum duration under any individual fuel supply contract and
transportation contract is 18 years and 21 years, respectively.
Reliant Resources' aggregate electric capacity commitments, including
capacity auction products, are for 7,496 MW, 1,800 MW, 1,000 MW, 1,000 MW and
1,000 MW for 2002, 2003, 2004, 2005 and 2006, respectively. The maximum duration
under any individual commitment is five years. Included in the above purchase
power and electric capacity commitments are amounts to be acquired from Texas
Genco in 2002 and 2003 of $213 million and $57 million, respectively.
As of December 31, 2001, Reliant Resources has commitments, including
electric energy and capacity sale contracts and district heating contracts (see
Note 14(h)) which are not classified as non-trading derivative assets and
liabilities or trading and marketing assets and liabilities in the Consolidated
Balance Sheets as these contracts meet the SFAS No. 133 exception to be
classified as "normal sales contracts" or do not meet the definition of a
derivative. The estimated minimum sale commitments under these contracts are
$450 million, $211 million, $194 million, $174 million and $159 million in 2002,
2003, 2004, 2005 and 2006, respectively.
In addition, in January 2002, Reliant Resources began providing retail
electric services to approximately 1.5 million residential and small commercial
customers previously served by Reliant Energy's electric utility division.
Within Reliant Energy's electric utility division's territory, prices that may
be charged to residential and small commercial customers by this retail electric
service provider are subject to a fixed, specified price (price to beat) at the
outset of retail competition. The Texas Utility Commission's regulations allow
this retail electric provider to adjust its price to beat fuel factor based on a
percentage change in the price of natural gas. In addition, the retail electric
provider may also request an adjustment as a result of changes in its price of
purchased energy. The retail electric provider may request that its price to
beat be adjusted twice a year.
75
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reliant Resources will not be permitted to sell electricity to residential and
small commercial customers in the incumbent's traditional service territory at a
price other than the price to beat until January 1, 2005, unless before that
date the Texas Utility Commission determines that 40% or more of the amount of
electric power that was consumed in 2000 by the relevant class of customers is
committed to be served by other retail electric providers.
Reliant Resources guarantees the performance of certain of its
subsidiaries' trading and hedging obligations. As of December 31, 2001, the
fixed maximum amount of such guarantees was $4.7 billion. In addition, Reliant
Resources has issued letters of credit totaling $51 million in connection with
its trading activities. Reliant Resources does not consider it likely that it
would be required to perform or otherwise incur any losses associated with these
guarantees.
In addition to the above discussions, Reliant Resources' other commitments
have various quantity requirements and durations and are not considered material
either individually or in the aggregate to its results of operations or cash
flows.
(b) LEASE COMMITMENTS
In August 2000, the Company, entered into separate sale-leaseback
transactions with each of three owner-lessors covering the subsidiaries'
respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and
Shawville generating stations, respectively, acquired in the REMA acquisition.
As lessee, the Company leases an interest in each facility from each
owner-lessor under a facility lease agreement. The equity interests in all the
subsidiaries of REMA are pledged as collateral for REMA's lease obligations. In
addition, the subsidiaries have guaranteed the lease obligations. The lease
documents contain restrictive covenants that restrict REMA's ability to, among
other things, make dividend distributions unless REMA satisfies various
conditions. The covenant restricting dividends would be suspended if the direct
or indirect parent of REMA, meeting specified criteria, including having a
rating on REMA's long-term unsecured senior debt of at least BBB from Standard
and Poor's and Baa2 from Moody's, guarantees the lease obligations. The Company
will make lease payments through 2029. The lease term expires in 2034. As of
December 31, 2001, REMA had $167 million of restricted funds that are available
for REMA's working capital needs and to make future lease payments, including a
lease payment of $55 million which was made in January 2002.
In the first quarter of 2001, Reliant Resources entered into tolling
arrangements with a third party to purchase the rights to utilize and dispatch
electric generating capacity of approximately 1,100 MW extending through 2012.
This electricity will be generated by two gas-fired, simple-cycle peaking
plants, with fuel oil backup which are being constructed by a tolling partner.
Reliant Resources anticipates construction to be completed by the summer of
2002, at which time Reliant Resources will commence tolling payments. The
tolling arrangements qualify as operating leases.
In February 2001, the Company entered into a lease for office space for
Reliant Resources in a building under construction. The lease agreement was
assigned by the Company to Reliant Resources by an assignment and assumption
agreement in June 2001. The lease term, which commences in the second quarter
2003, is 15 years with two five-year renewal options. Reliant Resources has the
right to name the building.
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2001, which primarily relate to the REMA leases mentioned above. Other
non-cancelable, long-term operating leases for Reliant Energy and Reliant
Resources principally
76
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
consist of tolling arrangements, as discussed above, rental agreements for
building space, data processing equipment and vehicles, including major work
equipment.
<Table>
<Caption>
REMA SALE-LEASE RELIANT RESOURCES RELIANT ENERGY
OBLIGATION OTHER OTHER TOTAL
--------------- ----------------- -------------- ------
(IN MILLIONS)
2002............................ $ 136 $ 52 $ 14 $ 202
2003............................ 77 72 12 161
2004............................ 84 87 7 178
2005............................ 75 89 6 170
2006............................ 64 90 5 159
2007 and beyond................. 1,124 469 66 1,659
------ ---- ---- ------
Total......................... $1,560 $859 $110 $2,529
====== ==== ==== ======
</Table>
Total lease expense for all operating leases was $39 million, $62 million
and $112 million during 1999, 2000 and 2001, respectively. During 2001, the
Company made lease payments related to the REMA lease of $259 million. As of
December 31, 2001, the Company had recorded a prepaid lease obligation related
to the REMA sale-leaseback of $59 million and $122 million in other current
assets and other long-term assets, respectively.
(c) CROSS BORDER LEASES
During the period from 1994 through 1997, under cross border lease
transactions, REPGB leased several of its power plants and related equipment and
turbines to non-Netherlands based investors (the head leases) and concurrently
leased the facilities back under sublease arrangements with remaining terms as
of December 31, 2001 of 1 to 23 years. REPGB utilized proceeds from the head
lease transactions to prepay its sublease obligations and to provide a source
for payment of end of term purchase options and other financial undertakings.
The initial sublease obligations totaled $2.4 billion of which $1.6 billion
remained outstanding as of December 31, 2001. These transactions involve REPGB
providing to a foreign investor an ownership right in (but not necessarily title
to) an asset, with a leaseback of that asset. The net proceeds to REPGB of the
transactions were recorded as a deferred gain and are currently being amortized
to income over the lease terms. At December 31, 2000 and 2001, the unamortized
deferred gain on these transactions totaled $77 million and $68 million,
respectively. The power plants, related equipment and turbines remain on the
financial statements of REPGB and continue to be depreciated.
REPGB is required to maintain minimum insurance coverages, perform minimum
annual maintenance and, in specified situations, post letters of credit. REPGB's
shareholder is subject to some restrictions with respect to the liquidation of
REPGB's shares. In the case of early termination of these contracts, REPGB would
be contingently liable for some payments to the sublessors, which at December
31, 2001, are estimated to be $272 million. Starting in March 2000, REPGB was
required by some of the lease agreements to obtain standby letters of credit in
favor of the sublessors in the event of early termination. The amount of the
required letters of credit was $272 million as of December 31, 2001. Commitments
for these letters of credit have been obtained as of December 31, 2001.
(d) NAMING RIGHTS TO HOUSTON SPORTS COMPLEX
In October 2000, Reliant Resources acquired the naming rights for the new
football stadium for the Houston Texans, the National Football League's newest
franchise. In addition, the naming rights cover the entertainment and convention
facilities included in the stadium complex. The agreement extends for 32 years.
In addition to naming rights, the agreement provides Reliant Resources with
significant sponsorship rights.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The aggregate cost of the naming rights will be approximately $300 million.
During the fourth quarter of 2000, Reliant Resources incurred an obligation to
pay $12 million in order to secure the long-term commitment and for the initial
advertising of which $10 million was expensed in the Statement of Consolidated
Income in 2000. Starting in 2002, when the new stadium is operational, Reliant
Resources will pay $10 million each year through 2032 for annual advertising
under this agreement.
(e) TRANSPORTATION AGREEMENT
A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR
Pipeline Company (ANR) that contemplated that this subsidiary would transfer to
ANR an interest in some of RERC Corp.'s pipeline and related assets. As of
December 31, 2000 and 2001, the Company had recorded $41 million in other
long-term liabilities in the Company's Consolidated Balance Sheets to reflect
the Company's obligation to ANR for the use of 130 million cubic feet (Mmcf)/day
of capacity in some of the Company's transportation facilities. The level of
transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5
million to ANR. The ANR Agreement will terminate in 2005 with a refund of $36
million.
(f) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Legal Matters
Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996,
the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a
proposed class of all similarly situated cities in Reliant Energy HL&P's service
area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a
wholly owned subsidiary of Reliant Energy) alleging underpayment of municipal
franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of
any kind for business conducted within these cities over the previous four
decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P
expressly impose fees only on its own receipts and only from sales of
electricity for consumption within a city, the Company regards all of
plaintiffs' allegations as spurious and is vigorously contesting the case. The
plaintiffs' pleadings asserted that their damages exceeded $250 million. The
269th Judicial District Court for Harris County granted partial summary judgment
in favor of Reliant Energy dismissing all claims for franchise fees based on
sales tax collections. Other motions for partial summary judgment were denied. A
six-week jury trial of the original claimant cities (but not the class of
cities) ended on April 4, 2000 (Three Cities case). Although the jury found for
Reliant Energy on many issues, they found in favor of the original claimant
cities on three issues, and assessed a total of $4 million in actual and $30
million in punitive damages. However, the jury also found in favor of Reliant
Energy on the affirmative defense of laches, a defense similar to a statute of
limitations defense, due to the original claimant cities having unreasonably
delayed bringing their claims during the 43 years since the alleged wrongs
began.
The trial court in the Three Cities case granted most of Reliant Energy's
motions to disregard the jury's findings. The trial court's rulings reduced the
judgment to $1.7 million, including interest, plus an award of $13.7 million in
legal fees. In addition, the trial court granted Reliant Energy's motion to
decertify the class and vacated its prior orders certifying a class. Following
this ruling, 45 cities filed individual suits against Reliant Energy in the
District Court of Harris County.
The Three Cities case has been appealed. The Company believes that the $1.7
million damage award resulted from serious errors of law and that it will be set
aside by the Texas appellate courts. In addition, the Company believes that
because of an agreement between the parties limiting fees to a percentage of the
damages, reversal of the award of $13.7 million in attorneys' fees in the Three
Cities case is probable.
The extent to which issues in the Three Cities case may affect the claims
of the other cities served by Reliant Energy HL&P cannot be assessed until
judgments are final and no longer subject to appeal. However, the trial court's
rulings disregarding most of the jury's findings are consistent with Texas
Supreme Court
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opinions over the past decade. The Company estimates the range of possible
outcomes for the plaintiffs to be between zero and $18 million inclusive of
interest and attorneys' fees.
California Wholesale Market. Reliant Energy, Reliant Energy Services, REPG
and several other subsidiaries of Reliant Resources, as well as three officers
of some of these companies, have been named as defendants in class action
lawsuits and other lawsuits filed against a number of companies that own
generation plants in California and other sellers of electricity in California
markets. Pursuant to the terms of the master separation agreement between
Reliant Energy and Reliant Resources (see Note 4(c)), Reliant Resources has
agreed to indemnify Reliant Energy for any damages arising under these lawsuits
and may elect to defend these lawsuits at its own expense. Three of these
lawsuits were filed in the Superior Court of the State of California, San Diego
County; two were filed in the Superior Court in San Francisco County; and one
was filed in the Superior Court of Los Angeles County. While the plaintiffs
allege various violations by the defendants of state antitrust laws and state
laws against unfair and unlawful business practices, each of the lawsuits is
grounded on the central allegation that defendants conspired to drive up the
wholesale price of electricity. In addition to injunctive relief, the plaintiffs
in these lawsuits seek treble the amount of damages alleged, restitution of
alleged overpayments, disgorgement of alleged unlawful profits for sales of
electricity, costs of suit and attorneys' fees. The cases were initially removed
to federal court and were then assigned to Judge Robert H. Whaley, United States
District Judge, pursuant to the federal procedures for multi-district
litigation. On July 30, 2000, Judge Whaley remanded the cases to state court.
Upon remand to state court, the cases were assigned to Superior Court Judge
Janis L. Sammartino pursuant to the California state coordination procedures. On
March 4, 2002, Judge Sammartino adopted a schedule proposed by the parties that
would result in a trial beginning on March 1, 2004. On March 8, 2002, the
plaintiffs filed a single, consolidated complaint naming numerous defendants,
including Reliant Energy Services and other Reliant Resources' subsidiaries,
that restated the allegations described above and alleged that damages against
all defendants could be as much as $1 billion.
Plaintiffs have voluntarily dismissed Reliant Energy from two of the three
class actions in which it was named as a defendant. The ultimate outcome of the
lawsuits cannot be predicted with any degree of certainty at this time. However,
the Company believes, based on its analysis to date of the claims asserted in
these lawsuits and the underlying facts, that resolution of these lawsuits will
not have a material adverse effect on the Company's financial condition, results
of operations or cash flows.
On March 11, 2002, the California Attorney General filed a civil lawsuit in
San Francisco Superior Court naming Reliant Energy, Reliant Resources, Reliant
Energy Services, REPG, and several other subsidiaries of Reliant Resources as
defendants. Pursuant to the terms of the master separation agreement between
Reliant Energy and Reliant Resources (see Note 4(c)), Reliant Resources has
agreed to indemnify Reliant Energy for any damages arising under these lawsuits
and may elect to defend these lawsuits at its own expense. The Attorney General
alleges various violations by the defendants of state laws against unfair and
unlawful business practices arising out of transactions in the markets for
ancillary services run by the California Independent System Operator (Cal ISO).
In addition to injunctive relief, the Attorney General seeks restitution and
disgorgement of alleged unlawful profits for sales of electricity, and civil
penalties. The ultimate outcome of this lawsuit cannot be predicted with any
degree of certainty at this time.
On March 19, 2002, the California Attorney General filed a complaint with
the FERC naming Reliant Energy Services and "all other public utility sellers"
in California as defendants. The complaint alleges that sellers with
market-based rates have violated their tariffs by not filing with the FERC
transaction-specific information about all of their sales and purchases at
market-based rates. The California Attorney General argues that, as a result,
all past sales should be subject to refund if found to be above just and
reasonable levels. The ultimate outcome of this complaint proceeding cannot be
predicted with any degree of certainty at this time. However, the Company
believes, based on its analysis to date of the claims asserted in the complaint,
the underlying facts, and the relevant statutory and regulatory provisions, that
resolution of this
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
lawsuit will not have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the
Federal False Claim Act against RERC and certain of its subsidiaries alleging
mismeasurement of natural gas produced from federal and Indian lands. The suit
seeks undisclosed damages, along with statutory penalties, interest, costs, and
fees. The complaint is part of a larger series of complaints filed against 77
natural gas pipelines and their subsidiaries and affiliates. An earlier single
action making substantially similar allegations against the pipelines was
dismissed by the U.S. District Court for the District of Columbia on grounds of
improper joinder and lack of jurisdiction. As a result, the various individual
complaints were filed in numerous courts throughout the country. This case was
consolidated, together with the other similar False Claim Act cases filed and
transferred to the District of Wyoming. Motions to dismiss were denied. The
defendants intend to vigorously contest this case.
In addition, RERC, REGT, REFS and MRT have been named as defendants in a
class action filed in May 1999 against approximately 245 pipeline companies and
their affiliates. The plaintiffs in the case purport to represent a class of
natural gas producers and fee royalty owners who allege that they have been
subject to systematic gas mismeasurement by the defendants, including certain
Reliant Energy entities, for more than 25 years. The plaintiffs seek
compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. The action is currently pending in state court in Stevens
County, Kansas. Plaintiffs initially sued Reliant Energy Services, but that
company was dismissed without prejudice on June 8, 2001. Other Reliant Energy
entities that were misnamed or duplicative have also been dismissed. MRT and
REFS have filed motions to dismiss for lack of personal jurisdiction and are
currently responding to discovery on personal jurisdiction. All four Reliant
Energy defendants have joined in a motion to dismiss.
The defendants plan to raise significant affirmative defenses based on the
terms of the applicable contracts, as well as on the broad waivers and releases
in take or pay settlements that were granted by the producer-sellers of natural
gas who are putative class members.
Environmental Matters
Clean Air Standards. The Company has participated in a lawsuit against the
Texas Natural Resource Conservation Commission (TNRCC) regarding the limitation
of the emission of oxides of nitrogen (NOx) in the Houston area. A settlement of
the lawsuit was reached with the TNRCC in the second quarter of 2001 and revised
emissions limitations were adopted by the TNRCC in the third quarter of 2001.
The revised limitations provide for an increase in allowable NOx emissions,
compared to the original TNRCC requirements, through 2004. Further emission
reduction requirements may or may not be required through 2007, depending upon
the outcome of further investigations of regional air quality issues. To achieve
the TNRCC NOx reduction requirements, the Company anticipates investing up to
$721 million in capital and other special project expenditures by 2004,
including costs incurred through December 31, 2001, and potentially up to an
additional $88 million between 2004 and 2007. The Texas Electric Restructuring
Law provides for stranded cost recovery for expenditures incurred before May 1,
2003 to achieve the NOx reduction requirements.
Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit
against Reliant Energy Gas Transmission Company, Inc., Reliant Energy Pipeline
Services, Inc., RERC, Reliant Energy Services, Inc., other Reliant Energy
entities and third parties (Docket No. 460, 916-Div. "B"), in the 1st Judicial
District Court, Caddo Parish, Louisiana. The petition has now been supplemented
five times. As of March 11, 2002, there were 628 plaintiffs, a majority of whom
are Louisiana residents who live near the Wilcox Aquifer. In addition to the
Reliant Energy entities, the plaintiffs have sued the State of Louisiana through
its Department of Environmental Quality, several individuals, some of whom are
present employees of the State of Louisiana, the Bayou South Gas Gathering
Company, L.L.C., Martin Timber Company, Inc., and several trusts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The suit alleges that, at some unspecified date prior to 1985, the
defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox
Aquifer which lies beneath property owned or leased by the defendants and which
is the sole or primary drinking water aquifer in the area. The primary source of
the contamination is alleged by the plaintiffs to be a gas processing facility
in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility." This
facility was purportedly used for gathering natural gas from surrounding wells,
separating gasoline and hydrocarbons from the natural gas for marketing, and
transmission of natural gas for distribution. This site was originally leased
and operated by predecessors of Reliant Energy Gas Transmission Company in the
late 1940s and was operated until Arkansas Louisiana Gas Company ceased
operations of the plant in the late 1970s.
Beginning about 1985, the predecessors of certain Reliant Energy defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they own or lease. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or dimunition of value of their
property, and in addition seek damages for trespass, punitive, and exemplary
damages. The quantity of monetary damages sought is unspecified. As of December
31, 2001, the Company is unable to estimate the monetary damages, if any, that
the plaintiffs may be awarded in this matter.
Manufactured Gas Plant Sites. RERC and its predecessors operated a
manufactured gas plant (MGP) until 1960 adjacent to the Mississippi River in
Minnesota, formerly known as Minneapolis Gas Works (MGW). RERC has substantially
completed remediation of the main site other than ongoing water monitoring and
treatment. The manufactured gas was stored in separate holders. RERC is
negotiating clean-up of one such holder. There are six other former MGP sites in
the Minnesota service territory. Remediation has been completed on one site. Of
the remaining five sites, RERC believes that two were neither owned nor operated
by RERC. RERC believes it has no liability with respect to the sites it neither
owned nor operated.
At December 31, 2000 and 2001, RERC had accrued $18 million and $23
million, respectively, for remediation of the Minnesota sites. At December 31,
2001, the estimated range of possible remediation costs was $11 million to $49
million. The cost estimates of the MGW site are based on studies of that site.
The remediation costs for the other sites are based on industry average costs
for remediation of sites of similar size. The actual remediation costs will be
dependent upon the number of sites remediated, the participation of other
potentially responsible parties (PRP), if any, and the remediation methods used.
Issues relating to the identification and remediation of MGPs are common in
the natural gas distribution industry. The Company has received notices from the
United States Environmental Protection Agency and others regarding its status as
a PRP for other sites. Based on current information, the Company has not been
able to quantify a range of environmental expenditures for potential remediation
expenditures with respect to other MGP sites.
Other Minnesota Matters. At December 31, 2000 and 2001, RERC had recorded
accruals of $4 million and $5 million, respectively for other environmental
matters in Minnesota for which remediation may be required. At December 31, 2001
the estimated range of possible remediation costs was $4 million to $8 million.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at sites found to be contaminated.
Although the Company is not aware of additional specific sites, it is possible
that other contaminated sites may exist and that remediation costs may be
incurred for these sites. Although the total
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
amount of these costs cannot be known at this time, based on experience by the
Company and that of others in the natural gas industry to date and on the
current regulations regarding remediation of these sites, the Company believes
that the costs of any remediation of these sites will not be material to the
Company's financial position, results of operations or cash flows.
REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see Note 3(a)), the Company became responsible for
liabilities associated with ash disposal site closures and site contamination at
the acquired facilities in Pennsylvania and New Jersey prior to a plant closing,
except for the first $6 million of remediation costs at the Seward Generating
Station. A prior owner retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. As of
December 31, 2000 and 2001, REMA has liabilities associated with six future ash
disposal site closures and six current site investigations and environmental
remediations. The Company has recorded its estimate of these environmental
liabilities in the amount of $36 million as of December 31, 2000 and 2001. The
Company expects approximately $16 million will be paid over the next five years.
REPGB Asbestos Abatement and Soil Remediation. Prior to the Company's
acquisition of REPGB (see Note 3(b)), REPGB had a $25 million obligation
primarily related to asbestos abatement, as required by Dutch law, and soil
remediation at six sites. During 2000, the Company initiated a review of
potential environmental matters associated with REPGB's properties. REPGB began
remediation in 2000 of the properties identified to have exposed asbestos and
soil contamination, as required by Dutch law and the terms of some leasehold
agreements with municipalities in which the contaminated properties are located.
All remediation efforts are to be fully completed by 2005. As of December 31,
2000 and 2001, the recorded estimated undiscounted liability for this asbestos
abatement and soil remediation was $24 million and $18 million, respectively.
Other. From time to time the Company has received notices from regulatory
authorities or others regarding its status as a PRP in connection with sites
found to require remediation due to the presence of environmental contaminants.
The Company has from time to time received notices from regulatory authorities
regarding alleged noncompliance with environmental regulatory requirements. In
addition, the Company has been named as a defendant in litigation related to
allegedly contaminated sites and in recent years has been named, along with
numerous others, as a defendant in several lawsuits filed by a large number of
individuals who claim injury due to exposure to asbestos while working at sites
along the Texas Gulf Coast. Most of these claimants have been workers who
participated in construction of various industrial facilities, including power
plants, and some of the claimants have worked at locations owned by the Company.
The Company anticipates that additional claims like those received may be
asserted in the future and intends to continue vigorously contesting claims
which it does not consider to have merit. Although their ultimate outcome cannot
be predicted at this time, the Company does not believe, based on its experience
to date, that these matters, either individually or in the aggregate, will have
a material adverse effect on the Company's financial position, results of
operations or cash flows.
Other Matters
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(g) CALIFORNIA WHOLESALE MARKET UNCERTAINTY.
Receivables. During portions of 2000 and 2001, prices for wholesale
electricity in California increased dramatically as a result of a combination of
factors, including higher natural gas prices and emission allowance costs,
reduction in available hydroelectric generation resources, increased demand,
decreased net electric imports and limitations on supply as a result of
maintenance and other outages. The resulting supply and demand imbalance
disproportionately impacted California utilities that relied too heavily on
short-term power markets to meet their load requirements. Although wholesale
prices increased, California's deregulation legislation kept retail rates frozen
at 10% below 1996 levels for two of California's public utilities, Pacific Gas
and Electric (PG&E) and Southern California Edison Company (SCE), until rates
were raised by the California Public Utilities Commission (CPUC) early in 2001.
Due to the disparity between wholesale and retail rates, the credit ratings
of PG&E and SCE fell below investment grade. Additionally, PG&E filed for
protection under the bankruptcy laws on April 6, 2001. As a result, PG&E and SCE
are no longer considered creditworthy and since January 17, 2001 have not
directly purchased power from third-party suppliers through the Cal ISO to serve
their net short load. Pursuant to emergency legislation enacted by the
California Legislature, the California Department of Water Resources (CDWR) has
negotiated and purchased power through short and long-term contracts on behalf
of PG&E and SCE to meet their net short loads. In December 2001, the CDWR began
making payments to the Cal ISO for real-time transactions. The CDWR has now made
payment through the Cal ISO for most real-time energy deliveries subsequent to
January 17, 2001.
In addition, certain contracts intended to serve as collateral for sales to
the California Power Exchange (Cal PX) were seized by California Governor Gray
Davis in February 2001. The Ninth Circuit Court of Appeals subsequently ruled
that Governor Davis' seizure of these contracts was wrongful. The Company has
filed a lawsuit, currently pending in California, to require the state of
California to compensate it for the seizure of these contracts. Although SCE
made a payment on March 1, 2002 to the Cal PX that included amounts it owed to
the Company under these contracts, the Company is still seeking to recover the
market value of the contracts at the time they were seized by Governor Davis,
which was significantly higher than the contract value, and to collect amounts
owed as a result of payment defaults by PG&E under the contracts. The timing and
ultimate resolution of these claims is uncertain at this time.
On September 20, 2001, PG&E filed a Plan of Reorganization and an
accompanying disclosure statement with the bankruptcy court. Under this plan,
PG&E would pay all allowed creditor claims in full, through a combination of
cash and long-term notes. Components of the plan will require the approval of
the FERC, the SEC and the Nuclear Energy Regulatory Commission, in addition to
the bankruptcy court. PG&E has stated it seeks to have this plan confirmed by
December 31, 2002. A number of parties are contesting PG&E's reorganization
plan, including a number of California parties and agencies. The bankruptcy
judge in the PG&E case has ordered that the CPUC may file a competing plan. The
details of the CPUC's proposal are unknown at this time. The ability of PG&E to
have its reorganization plan confirmed, including the provision providing for
the payment in full of unsecured creditors, is uncertain at this time.
On October 5, 2001, a federal district court in California entered a
stipulated judgment approving a settlement between SCE and the CPUC in an action
brought by SCE regarding the recovery of its wholesale power costs under the
filed rate doctrine. Under the stipulated judgment, a rate increase approved
earlier in 2001 will remain in place until the earlier of SCE recovering $3.3
billion or December 31, 2002. After that date, the CPUC will review the
sufficiency of retail rates through December 31, 2005. A consumer organization
has appealed the judgment to the Ninth Circuit Court of Appeals, and no hearing
has been held to date. Under the stipulated judgment, any settlement with SCE's
creditors that is entered into after March 1, 2002 must be approved by the CPUC.
The Company has appealed this provision of the judgment. On March 1, 2002, SCE
made a payment to the Cal PX that included amounts it owed the Company. The
Company has made a filing with FERC seeking an order providing for the
disbursement of the funds owed to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the suppliers. The FERC and the bankruptcy court governing the Cal PX bankruptcy
proceedings are considering how to dispense this money and it remains uncertain
when those funds will be paid over to the Company.
As of December 31, 2000, the Company was owed a total of $282 million by
the Cal PX and the Cal ISO. As of December 31, 2001, the Company was owed a
total of $302 million by the Cal ISO, the Cal PX, the CDWR, and California
Energy Resources Scheduling for energy sales in the California wholesale market
during the fourth quarter of 2000 through December 31, 2001. From January 1,
2002 through March 26, 2002, the Company has collected $45 million of these
receivable balances. As of December 31, 2001, the Company had a pre-tax
provision of $68 million against receivable balances related to energy sales in
the California market, including $39 million recorded in 2000 and $29 million
recorded in 2001. Management will continue to assess the collectability of these
receivables based on further developments affecting the California electricity
market and the market participants described herein.
FERC Market Mitigation. In response to the filing of a number of
complaints challenging the level of wholesale prices, the FERC initiated a staff
investigation and issued a number of orders implementing a series of wholesale
market reforms. Under these orders, and subject to review and adjustment based
on the pending refund proceeding described below, the Company may face an as yet
undetermined amount of refund liability. See "-- FERC Refunds" below. Under
these orders, for the period January 1, 2001 through June 19, 2001,
approximately $20 million of the $149 million charged by the Company for sales
in California to the Cal ISO and the Cal PX were identified as being subject to
possible refunds. During the second quarter of 2001, the Company accrued refunds
of $15 million, $3 million of which had been previously expensed during the
first quarter of 2001.
On April 26, 2001, the FERC issued an order replacing the previous price
review procedures and establishing a market monitoring and mitigation plan,
effective May 29, 2001, for the California markets. The plan establishes a cap
on prices during periods when power reserves fall below 7% in the Cal ISO
(reserve deficiency periods). The Cal ISO is instructed to use data submitted
confidentially by gas-fired generators in California and daily indices of
natural gas and emissions allowance costs to establish the market-clearing price
in real-time based on the marginal cost of the highest-cost generator called to
run. The plan also requires generators in California to offer all their
available capacity for sale in the real-time market, and conditions sellers'
market-based rate authority such that sellers engaging in certain bidding
practices will be subject to increased scrutiny by the FERC, potential refunds
and even revocation of their market-based rate authority.
On June 19, 2001, the FERC issued an order modifying the market monitoring
and mitigation plan adopted in its April 26 order, to apply price controls to
all hours, instead of just hours of low operating reserve, and to extend the
mitigation measures to other Western states in addition to California, including
Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington
and Wyoming. The FERC set July 2, 2001 as the refund effective date for sales
subject to the price mitigation plan throughout the West region. This means that
transactions after that date may be subject to refund if found to be unjust or
unreasonable. The proxy market clearing price calculated by the Cal ISO will
apply during periods of reserve deficiency to all sales in the Cal ISO and
Western spot markets. In non-reserve deficiency hours in California, the maximum
price in California and the other Western states will be capped at 85% of the
highest Cal ISO hourly market clearing price established during the most recent
reserve deficiency period. Sellers other than marketers will be allowed to bid
higher than the maximum prices, but such bids are subject to justification and
potential refund. Justification of higher prices is limited to establishing
higher actual gas costs than the proxy calculation averages and making a showing
that conditions in natural gas markets changed significantly. The modified
monitoring and mitigation plan went into effect June 20, 2001, and will
terminate on September 30, 2002, covering two summer peak seasons, or
approximately 16 months.
On December 19, 2001, the FERC issued a series of orders on price
mitigation in California and the West region. These orders largely maintained
existing mitigation mechanisms, but did make a temporary modifica-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tion to the way that mitigated market clearing prices will be set during the
winter months, allowing the maximum prices to rise if gas prices rise. The FERC
removed the requirement that non-reserve deficiency prices be limited to 85% of
the most recent reserve deficiency prices, allowing prices to rise to a
mitigated clearing price of $108/MWh (above which price transactions must be
justified as described above). In addition, the FERC determined that if gas
prices in California rise by 10%, the mitigated price may be revised to take
that change into account. The formula will then track subsequent cumulative
changes of at least 10%, but may not fall below a maximum price of $108/MWh.
This modification is effective December 20, 2001 through April 30, 2002, at
which point the previous mitigation formula is reinstated.
Also, the December 19 orders affirm the June 19 order's requirement that
generators must offer all available capacity for sale in the real-time market.
As a result of this requirement, the Company's opportunity to sell ancillary
services in the West region in the future may be reduced. During 2001, the
Company recorded $42 million in revenues related to ancillary services in the
West region.
In addition to the impact on ancillary services sales, certain aspects of
the December 19, 2001 orders may have retroactive application that may affect
prices charged in the West region since June 21, 2001. Because the precise
application of the December 19, 2001 order is not known at this time, the
Company cannot anticipate the resulting impact on earnings.
The Company believes that while the mitigation plan will reduce volatility
in the market, the Company will nevertheless be able to profitably operate its
facilities in the West. Additionally, as noted above, the mitigation plan allows
sellers, such as the Company, to justify prices above the proxy price. However,
previous efforts by the Company to justify prices above the proxy price have
been rejected by the FERC and there is no certainty that the FERC will allow for
the recovery of costs above the proxy price. Finally, any adverse impacts of the
mitigation plan on the Company's operations would be mitigated, in part, by the
Company's forward hedging activities.
FERC Refunds. The FERC issued an order on July 25, 2001 adopting a refund
methodology and initiating a hearing schedule to determine (1) revised mitigated
prices for each hour from October 2, 2000 through June 20, 2001; (2) the amount
owed in refunds by each supplier according to the methodology (these amounts may
be in addition to or in place of the refund amounts previously determined by the
FERC); and (3) the amount currently owed to each supplier. The amounts of any
refunds will be determined by the FERC after the conclusion of the hearing
process. On December 19, 2001, the FERC issued an order modifying the
methodology to be used to determine refund amounts. The schedule currently
anticipates that the Administrative Law Judge will make his refund amount
recommendations to the FERC in October 2002. However, the Company does not know
when the FERC will issue its final decision. The Company has not reserved any
amounts for potential future refund liability resulting from the FERC refund
hearing, nor can it currently predict the amount of these potential refunds, if
any, because the methodology used to calculate these refunds is not final and
will depend on information that is still subject to review and challenge in the
hearing process. Any refunds that are determined in the FERC proceeding will
likely be offset against unpaid amounts owed, if any, to the Company for its
prior sales.
On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including the Company. In this proceeding, the
FERC conditions the market-based rate authority of all sellers on their not
engaging in anti-competitive behavior. Such condition will apply upon a further
order from FERC establishing a refund effective date. This condition allows the
FERC, if it determines that a seller has engaged in anti-competitive behavior
subsequent to the start of the refund effective period, to order refunds back to
the date of such behavior. The FERC invited comments regarding this proposal,
and the Company has filed comments in opposition to the proposal. On March 11,
2002, the FERC's Staff held a conference with market participants to discuss the
comments FERC has received, and possible modification of the proposed conditions
to address concerns raised in the comments while protecting consumers against
anticompetitive behavior. The timing of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
further action by FERC is uncertain. If the FERC does not modify or reject its
proposed approach for dealing with anti-competitive behavior, the Company's
future earnings may be affected by the open-ended refund obligation.
On February 13, 2002, the FERC issued an order initiating a staff
investigation into potential manipulation of electric and natural gas prices in
the Western region for the period January 1, 2000 forward. While this order does
not propose any action against the Company, if the investigation results in
findings that markets were dysfunctional during this period, those findings may
be used in support of existing or future claims by the FERC or others that
prices in the Company's long-term contracts entered into after January 1, 2000
for sales in the West region should be altered.
Other Investigations. In addition to the FERC investigation discussed
above, several state and other federal regulatory investigations and complaints
have commenced in connection with the wholesale electricity prices in California
and other neighboring Western states to determine the causes of the high prices
and potentially to recommend remedial action. In California, the California
State Senate and the California Office of the Attorney General have separate
ongoing investigations into the high prices and their causes. Although these
investigations have not been completed and no findings have been made in
connection with either of them, the California Attorney General has filed a
civil lawsuit in San Francisco Superior Court alleging that the Company has
violated state laws against unfair and unlawful business practices and a
complaint with the FERC alleging the Company violated the terms of its tariff
with the FERC (see Note 14(f)). Adverse findings or rulings could result in
punitive legislation, sanctions, fines or even criminal charges against the
Company or its employees. The Company is cooperating with both investigations
and has produced a substantial amount of information requested in subpoenas
issued by each body. The Washington and Oregon attorneys general have also begun
similar investigations.
Legislative Efforts. Since the inception of the California energy crisis,
various pieces of legislation, including tax proposals, have been introduced in
the U.S. Congress and the California Legislature addressing several issues
related to the increase in wholesale power prices in 2000 and 2001. For example,
a bill was introduced in the California legislature that would have created a
"windfall profits" tax on wholesale electricity sales and would subject exempt
wholesale generators, such as the Company's subsidiaries that own generation
facilities in California, to regulation by the CPUC as "public utilities." To
date, only a few energy-related bills have passed and the Company does not
believe that the legislation that has been enacted to date on these issues will
have a material adverse effect on the Company. However, it is possible that
legislation could be enacted on either the state or federal level that could
have a material adverse effect on the Company's financial condition, results of
operations and cash flows.
(h) INDEMNIFICATION OF STRANDED COSTS
Background. In January 2001, the Dutch Electricity Production Sector
Transitional Arrangements Act (Transition Act) became effective and, among other
things, allocated to REPGB and the three other large-scale Dutch generation
companies, a share of the assets, liabilities and stranded cost commitments of
NEA. Prior to the enactment of the Transition Act, NEA acted as the national
electricity pooling and coordinating body for the generation output of REPGB and
the three other large-scale national Dutch generation companies. REPGB and the
three other large-scale Dutch generation companies are shareholders of NEA.
The Transition Act and related agreements specify that REPGB has a 22.5%
share of NEA's assets, liabilities and stranded cost commitments. NEA's stranded
cost commitments consisted primarily of various uneconomical or stranded cost
investments and commitments, including a gas supply and three power contracts
entered into prior to the liberalization of the Dutch wholesale electricity
market. REPGB's stranded cost obligations also include uneconomical district
heating contracts which were previously administrated by NEA prior to
deregulation of the Dutch power market.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The gas supply contract expires in 2016 and provides for gas imports
aggregating 2.283 billion cubic meters per year. Prior to December 31, 2001, one
of the stranded cost power contracts was settled. The two remaining stranded
cost power contracts have the following capacities and terms: (a) 300 MW through
2005, and (b) 600 MW through March 2002 and 750 MW through 2009. Under the
Transition Act, REPGB can either assume its 22.5% allocated interest in the
contracts or, subject to the terms of the contracts, sell its interests to third
parties. The district heating obligations relate to three heating water supply
contacts entered into with various municipalities and expire from 2013 through
2015. Under the district heating contracts, the municipal districts are required
to take annually a combined minimum of 5,549 terajoules (TJ) increasing annually
to 7,955 TJ over the life of the contracts.
The Transition Act also authorized the government to purchase from NEA at
least a majority of the shares in the Dutch national transmission grid company
which was sold to the Dutch government on October 25, 2001 for approximately NLG
2.6 billion (approximately $1.05 billion based on an exchange rate of 2.48 NLG
per U.S. dollar as of December 31, 2001).
Prior to December 31, 2001, the former shareholders agreed pursuant to a
share purchase agreement to indemnify REPGB for up to NLG 1.9 billion in
stranded cost liabilities (approximately $766 million). The indemnity obligation
of the former shareholders and various provincial and municipal entities
(including the city of Amsterdam), was secured by a NLG 900 million escrow
account (approximately $363 million).
The Transition Act provided that, subject to the approval of the European
Commission, the Dutch government will provide financial compensation to the
Dutch generation companies, including REPGB, for liabilities associated with (a)
long-term district heating contracts and (b) an experimental coal facility. In
July 2001, the European Commission ruled that under certain conditions the Dutch
government can provide financial compensation to the generation companies for
the district heating contracts. To the extent that this compensation is not
ultimately provided to the generation companies by the Dutch government, REPGB
was to collect its compensation directly from the former shareholders as further
discussed below.
In January 2001, the Company recognized an out-of-market, net stranded cost
liability for its gas and electric contracts and district heating commitments.
At such time, the Company recorded a corresponding asset of equal amount for the
indemnification of this obligation from REPGB's former shareholders and the
Dutch government, as applicable. Pursuant to SFAS No. 133, the gas and electric
contracts are marked-to-market (see Note 5). As of December 31, 2001, the
Company has recorded a liability of $369 million for its stranded cost gas and
electric commitments in non-trading derivative liabilities and a liability of
$206 million for its district heating commitments in current and non-current
other liabilities. As of December 31, 2001, the Company has recorded an
indemnification receivable from the Dutch government for the district heating
stranded cost liability of $206 million. The settlement of the indemnification
related to gas and electric contract commitments in December 2001 is discussed
below.
Settlement of Stranded Cost Indemnification. In December 2001, REPGB and
its former shareholders entered into a settlement agreement immediately
resolving the former shareholders of their stranded cost indemnity obligations
related to the gas supply and power contracts under the original share purchase
agreement, and provides conditional terms for the possible settlement of their
stranded cost indemnity obligation related to district heating obligations under
certain conditions. The settlement agreement was approved in December 2001 by
the Ministry of Economic Affairs of the Netherlands.
Under the settlement agreement, the former shareholders paid to REPGB NLG
500 million ($202 million) in January and February 2002. The payment represents
a settlement of the obligations of the former shareholders to indemnify REPGB
for all stranded cost liabilities other than those relating to the district
heating contracts. The full amount of this payment was placed into an escrow
account in the name of REPGB to fund its stranded cost obligations related to
the gas and electric import contracts. Any remaining escrow funds as of January
1, 2004 will be distributed to REPGB.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Under the settlement agreement, the former shareholders will continue to
indemnify REPGB for the stranded cost liabilities relating to district heating
contracts. The terms of the indemnity are as follows:
- The settlement agreement acknowledges that the Netherlands is finalizing
regulations for compensation of stranded cost associated with district
heating projects. Within 21 days after the date these compensation rules
take effect, REPGB can elect to receive one of two forms of
indemnification under the settlement agreement.
- If the compensation to be paid by the Netherlands under these rules is at
least as much as the compensation to be paid under the original
indemnification agreement, REPGB can elect to receive a one-time payment
of NLG 60 million ($24 million). In addition, unless the decree
implementing the new compensation rules provides for compensation for the
lifetime of the district heating projects, REPGB can receive an
additional cash payment of NLG 15 million ($6 million).
- If the compensation rules do not provide for compensation at least equal
to that provided under the original indemnification agreement, REPGB can
claim indemnification for stranded cost losses up to a maximum of NLG 700
million ($282 million) less the amount of compensation provided by the
new compensation rules and certain proceeds received from arbitrations.
- If no new compensation rules have taken effect on or prior to December
31, 2003, REPGB is entitled, but not obligated, to elect to receive
indemnification under the formula described above.
Under the terms of the original indemnification agreement, the former
shareholders were entitled to receive any and all distributions and dividends
above NLG 125 million ($51 million) paid by NEA. Under the settlement agreement,
the former shareholders waived all rights under the original indemnification
agreement to claim distributions of NEA.
Reliant Resources recognized a net gain of $37 million for the difference
between the sum of (a) the cash settlement payment of $202 million and the
additional rights to claim distributions of Reliant Resources' NEA investment
recognized of $248 million and (b) the amount recorded as stranded cost
indemnity receivable related to the stranded cost gas and electric commitments
of $369 million and claims receivable related to stranded cost incurred in 2001
of $44 million both previously recorded in the Consolidated Balance Sheets.
Investment in NEA. During the second quarter of 2001, Reliant Resources
recorded a $51 million pre-tax gain (NLG 125 million) recorded as equity income
for the preacquisition gain contingency related to the acquisition of REPGB for
the value of its equity investment in NEA. This gain was based on Reliant
Resources' evaluation of NEA's financial position and fair value. The fair value
of Reliant Resources' investment in NEA is dependent upon the ultimate
resolution of its existing contingencies and proceeds received from liquidating
its remaining net assets. Prior to the settlement agreement discussed above,
pursuant to the purchase agreement of REPGB, as amended, REPGB was entitled to a
NLG 125 million dividend from NEA with any remainder owing to the former
shareholders. As mentioned above, REPGB entered into an agreement with its
former shareholders to settle the original indemnification agreement and the
former shareholders waived all rights to distributions of NEA. Accordingly, as a
component of the net gain recognized from the settlement of the stranded cost
indemnity, Reliant Resources recorded a $248 million increase in its investment
in NEA. As of December 31, 2001, Reliant Resources has recorded $299 million in
equity investments of unconsolidated subsidiaries for its investment in NEA.
(i) OPERATIONS AGREEMENT WITH CITY OF SAN ANTONIO
As part of the 1996 settlement of certain litigation claims asserted by the
City of San Antonio with respect to the South Texas Project, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
order to take advantage of each system's lower cost resources. In January 2000,
the contract term was extended for three years and is expected to terminate in
2009. Under the terms of the joint operations agreement entered into between CPS
and Electric Operations, the Company has guaranteed CPS minimum annual savings
of $10 million up to a total cumulative savings of $150 million over the term of
the agreement. The cumulative obligation was met in the first quarter of 2001.
In 1999, 2000 and 2001, savings generated for CPS' account were $14 million, $60
million and $65 million, respectively. Through December 31, 2001, cumulative
savings generated for CPS' account were $189 million.
(j) NUCLEAR INSURANCE
The Company and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of December 31, 2001. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. The Company and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan.
There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.
(k) NUCLEAR DECOMMISSIONING
The Company contributed $14.8 million per year in 1999, 2000 and 2001 to a
trust established to fund its share of the decommissioning costs for the South
Texas Project. Pursuant to the October 3, 2001 Order, beginning in 2002, the
Company will contribute $2.9 million per year to this trust. There are various
investment restrictions imposed upon the Company by the Texas Utility Commission
and the NRC relating to the Company's nuclear decommissioning trust.
Additionally, the Company's board of directors has appointed the Nuclear
Decommissioning Trust Investment Committee to establish the investment policy of
the trust and oversee the investment of the trusts' assets. The securities held
by the trust for decommissioning costs had an estimated fair value of $169
million as of December 31, 2001, of which approximately 46% were fixed-rate debt
securities and the remaining 54% were equity securities. For a discussion of the
accounting treatment for the securities held in the Company's nuclear
decommissioning trust, see Note 2(l). In July 1999, an outside consultant
estimated the Company's portion of decommissioning costs to be approximately
$363 million. While the current funding levels currently exceed minimum NRC
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning
and changes in regulatory requirements, technology and costs of labor, materials
and equipment. Pursuant to the Texas Electric Restructuring Law, costs
associated with nuclear decommissioning that have not been recovered as of
January 1, 2002, will continue to be subject to cost-of-service rate regulation
and will be included in a charge to transmission and distribution customers. For
information regarding the effect of the Business Separation Plan on funding of
the nuclear decommissioning trust fund, see Note 4(b).
(l) CONSTRUCTION AGENCY AGREEMENT AND EQUIPMENT FINANCING STRUCTURE
In 2001, Reliant Resources, through several of its subsidiaries, entered
into operative documents with special purpose entities to facilitate the
development, construction, financing and leasing of several power
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
generation projects. The special purpose entities are not consolidated by the
Company. The special purpose entities have an aggregate financing commitment
from equity and debt participants (Investors) of $2.5 billion of which the last
$1.1 billion is currently available only if the cash is collateralized. The
availability of the commitment is subject to satisfaction of various conditions,
including the obligation to provide cash collateral for the loans and letters of
credit outstanding on November 27, 2004. Reliant Resources, through several of
its subsidiaries, acts as construction agent for the special purpose entities
and is responsible for completing construction of these projects by December 31,
2004, but Reliant Resources has generally limited its risk during construction
to an amount not in excess of 89.9% of costs incurred to date, except in certain
events. Upon completion of an individual project and exercise of the lease
option, Reliant Resources' subsidiaries will be required to make lease payments
in an amount sufficient to provide a return to the Investors. If Reliant
Resources does not exercise its option to lease any project upon its completion,
Reliant Resources must purchase the project or remarket the project on behalf of
the special purpose entities. Reliant Resources' ability to exercise the lease
option is subject to certain conditions. Reliant Resources must guarantee that
the Investors will receive an amount at least equal to 89.9% of their investment
in the case of a remarketing sale at the end of construction. At the end of an
individual project's initial operating lease term (approximately five years from
construction completion), Reliant Resources' subsidiary lessees have the option
to extend the lease with the approval of Investors, purchase the project at a
fixed amount equal to the original construction cost, or act as a remarketing
agent and sell the project to an independent third party. If the lessees elect
the remarketing option, they may be required to make a payment of an amount not
to exceed 85% of the project cost, if the proceeds from remarketing are not
sufficient to repay the Investors. Reliant Resources has guaranteed the
performance and payment of its subsidiaries' obligations during the construction
periods and, if the lease option is exercised, each lessee's obligations during
the lease period. At any time during the construction period or during the
lease, Reliant Resources may purchase a facility by paying an amount
approximately equal to the outstanding balance plus costs.
Reliant Resources, through its subsidiary, REPG, has entered into an
agreement with a bank whereby the bank, as owner, entered or will enter into
contracts for the purchase and construction of power generation equipment and
REPG, or its subagent, acts as the bank's agent in connection with administering
the contracts for such equipment. Under the agreement, the bank has agreed to
provide up to a maximum aggregate amount of $650 million. REPG and its subagents
must cash collateralize their obligation to administer the contracts. This cash
collateral is approximately equivalent to the total payments by the bank for the
equipment, interest and other fees. As of December 31, 2001, the bank had
assumed contracts for the purchase of eleven turbines, two heat recovery steam
generators and one air-cooled condenser with an aggregate cost of $398 million.
REPG, or its designee, has the option at any time to purchase, or, at equipment
completion, subject to certain conditions, including the agreement of the bank
to extend financing, to lease the equipment, or to assist in the remarketing of
the equipment under terms specified in the agreement. All costs, including the
purchase commitment on the turbines, are the responsibility of the bank. The
cash collateral is deposited by REPG or an affiliate into a collateral account
with the bank and earns interest at LIBOR less 0.15%. Under certain
circumstances, the collateral deposit or a portion of it, will be returned to
REPG or its designee. Otherwise, it will be retained by the bank. At December
31, 2001, REPG and its subsidiary had deposited $230 million into the collateral
account. The bank's payments for equipment under the contracts totaled $227
million as of December 31, 2001. In January 2002, the bank sold to the parties
to the construction agency agreements discussed above, equipment contracts with
a total contractual obligation of $258 million, under which payments and
interest during construction totaled $142 million. Accordingly, $142 million of
Reliant Resources' collateral deposits were returned to Reliant Resources. As of
December 31, 2001, there were equipment contracts with a total contractual
obligation of $140 million under which payments during construction totaled $83
million. Currently this equipment is not designated for current planned power
generation construction projects. Therefore, the Company anticipates that it
will either purchase the equipment, assist in the remarketing of the equipment
or negotiate to cancel the related contracts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(21) BANKRUPTCY OF ENRON CORP. AND ITS AFFILIATES
During the fourth quarter of 2001, Enron filed a voluntary petition for
bankruptcy. Accordingly, the Company recorded an $85 million provision,
comprised of provisions against 100% of receivables of $88 million and net
non-trading derivative balances of $52 million, offset by the Company's net
trading and marketing liabilities to Enron of $55 million.
The non-trading derivatives with Enron were designated as Cash Flow Hedges
(see Note 5). The net gain on these derivative instruments previously reported
in other comprehensive income will remain in accumulated other comprehensive
loss and will be reclassified into earnings during the period in which the
originally designated hedged transactions occur.
(22) SUBSEQUENT EVENTS
(a) ORION POWER HOLDINGS, INC.
In February 2002, Reliant Resources acquired all of the outstanding shares
of Orion Power for $26.80 per share in cash for an aggregate purchase price of
$2.9 billion. Reliant Resources funded the Orion Power acquisition with a term
loan supported by a $2.9 billion credit facility and $41 million of cash on
hand. Interest rates on the term loan are based on LIBOR plus a margin or a base
rate. The term loan must be repaid within one year from the date on which it was
funded. As a result of the acquisition, Reliant Resources' consolidated net debt
obligations also increased by the amount of Orion Power's net debt obligations.
As of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of cash acquired some of which is restricted pursuant to debt
covenants). Orion Power is an independent electric power generating company
formed in March 1998 to acquire, develop, own and operate power-generating
facilities in certain deregulated wholesale markets throughout North America. As
of February 28, 2002, Orion Power had 81 power plants in operation with a total
generating capacity of 5,644 MW and an additional 804 MW in construction or in
various stages of development.
(b) FACTORING AGREEMENT
In the first quarter of 2002, RERC reduced its trade receivables facility
from $350 million to $150 million. Borrowings under the receivables facility
aggregating $196 million were repaid in January 2002 with proceeds from the
issuance of commercial paper under RERC's $350 million revolving credit facility
and from the liquidation of short-term investments.
(c) INTEREST RATE SWAPS
In the first quarter of 2002, the Company entered into interest rate swaps
with an aggregate notional amount of $1.25 billion. Swaps with a notional amount
of $250 million were entered into for the purpose of fixing rates on short-term
debt subject to interest rate fluctuations and do not qualify as cash flow
hedges under SFAS No. 133. The swaps with a notional amount of $1 billion were
entered into to hedge the interest rate on a future offering of five-year fixed
rate notes. These swaps qualify as cash flow hedges under SFAS No. 133.
91