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EXHIBIT 99.REI
RELIANT ENERGY, INCORPORATED
ITEMS INCORPORATED BY REFERENCE
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K
o ITEM 3. LEGAL PROCEEDINGS.
(a) RELIANT ENERGY.
For a description of certain legal and regulatory proceedings affecting
Reliant Energy, see Notes 4, 14(g), 14(h) and 14(i) to our consolidated
financial statements, which notes are incorporated herein by reference.
o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS
Our earnings for the past three years are not necessarily indicative of our
future earnings and results. The level of our future earnings depends on
numerous factors including:
- state and federal legislative, as well as international regulatory
developments, including deregulation, re-regulation and restructuring of
the electric utility industry and changes in or application of
environmental and other laws and regulations to which we are subject,
- the timing of the implementation of our Business Separation Plan,
- industrial, commercial and residential growth in our service territories,
- 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 commodity prices and interest rates,
- weather variations and other natural phenomena,
- our ability to cost-effectively finance and refinance,
- the determination of the amount of our Texas generating assets' stranded
costs and the recovery of these costs,
- the ability to consummate and the timing of the consummation of
acquisitions and dispositions,
- the performance of our generation projects undertaken,
- the successful operation of deregulating power markets, including the
resolution of the crisis in the California market, and
- risks incidental to our overseas operations, including the effects of
fluctuations in foreign currency exchange rates.
In order to adapt to the increasingly competitive environment, 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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BUSINESS SEPARATION AND RESTRUCTURING
In anticipation of electric deregulation in Texas, and pursuant to the
Legislation, we submitted a business separation plan in January 2000 to the
Texas Utility Commission. Pursuant to the Business Separation Plan, we will
restructure our businesses into two separate publicly traded companies in order
to separate our unregulated businesses from our rate-regulated businesses.
Reliant Resources holds substantially all of our unregulated businesses. We
expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate
that the Regulated Holding Company will conduct the Distribution within 12
months of the completion of the Offering, subject to receipt of a favorable tax
ruling and other regulatory approvals. For additional information regarding the
Business Separation Plan and the Restructuring, please read "Business -- Our
Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our
consolidated financial statements.
We have sought a ruling from the Internal Revenue Service that the
Distribution will be tax-free to the Regulated Holding Company and its
shareholders. At this time, we do not have a ruling from the Internal Revenue
Service regarding the tax treatment of the Distribution. If we do not obtain a
favorable tax ruling, the Distribution is not likely to be made in the expected
time frame or, perhaps, at all. In order for the Distribution to be tax-free,
various requirements must be met, including ownership by its parent of at least
80% of all classes of Reliant Resources' outstanding capital stock at the time
of the Distribution.
Additionally, in connection with the Distribution, Reliant Energy plans to
restructure its remaining businesses to achieve a public utility holding company
structure and to register the Regulated Holding Company as a public utility
holding company under the 1935 Act. Creation of the Regulated Holding Company
will require the approval of Reliant Energy's shareholders. For additional
information regarding the Regulated Holding Company, please read
"Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note
4(b) to our consolidated financial statements. The Restructuring will also
require the approval of the Louisiana Public Service Commission and the Nuclear
Regulatory Commission. We cannot assure you that those approvals will be
obtained. After the Restructuring, the Regulated Holding Company will become a
registered public utility holding company under the 1935 Act.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS
Competition and Deregulation. In June 1999, the Texas legislature adopted
the Legislation, 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 will begin
in June 2001 and retail electric competition for all other customers will begin
on January 1, 2002. Our retail operations will be conducted by indirect wholly
owned subsidiaries of Reliant Resources. Under the market framework established
by the Legislation, we will initially be required to sell electricity to Houston
area residential and small commercial customers at a specified price, which is
referred to in the Legislation as the "price to beat," whereas other retail
electric providers will be allowed to sell electricity to these same customers
at any price. We will not be 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 residential or small commercial
customers, as applicable, within the affiliated transmission and distribution
utility's certificated service territory, as of January 1, 2002, is committed to
be served by other retail electric providers. In addition, as long as we
continue to provide retail service, the Legislation requires us to make the
price to beat available to residential and small commercial customers in Reliant
Energy HL&P's service territory through January 1, 2007. Because we will not be
able to compete for residential and small commercial customers on the basis of
price in Reliant Energy HL&P's service area, and because we expect that the
retail market framework established by the Legislation will encourage
competition from new retail electric providers, we could lose a significant
number of these customers to other providers. When the pilot projects begin in
June 2001, and until full retail electric competition begins, the Legislation
provides that 5% of our customers may elect to purchase electricity from other
retail electric providers. Our affiliated retail electric providers cannot
participate in the pilot projects in Reliant Energy HL&P's service area. Reliant
Energy HL&P will collect from retail electric providers the rates approved from
its Wires Case to cover the cost of providing transmission and distribution
service and any other non-bypassable charges.
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Generally, retail electric providers will procure or buy electricity from
the wholesale generators at unregulated rates, sell electricity at retail to
their customers and pay the transmission and distribution utility a regulated
tariffed rate for delivering the electricity to their customers. The results of
our retail electric operations will be largely dependent upon the amount of
gross margin, or "headroom," available in the "price to beat." The available
headroom will equal the difference between the price to beat and the sum of the
charges, fees and transmission and distribution utility rate approved by the
Texas Utility Commission and the price we pay for power to meet our price to
beat load. The larger the amount of headroom, the more incentive new market
entrants should have to provide retail electric services in Reliant Energy
HL&P's service territory. The Texas Utility Commission's regulations allow us to
adjust our price to beat fuel factor based on the percentage change in the price
of natural gas. In addition, we may also request an adjustment as a result of
changes in our price of purchased energy. In such a request, we may adjust the
fuel factor to the extent necessary to restore the amount of headroom that
existed at the time our initial price to beat fuel factor was set by the Texas
Utility Commission. We may not request that our price to beat be adjusted more
than twice a year. Currently, we do not know nor can we estimate the amount of
headroom in our initial price to beat or in the initial price to beat for the
affiliated retail electric provider in each other Texas retail electric market.
Similarly, we cannot estimate with any certainty the magnitude and frequency of
the adjustments required, if any, and the eventual impact of such adjustments on
the amount of headroom.
In preparation for this competition, we expect to make significant changes
in the electric utility operations currently conducted through Reliant Energy
HL&P. For additional information regarding these changes, the Legislation,
retail competition, its application to our Electric Operations segment and the
"price to beat," please read "Business -- Our Business -- Deregulation and
Competition," "-- Restructuring," "-- Electric Operations" and
"Business -- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our
consolidated financial statements.
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 "-- Competitive, Regulatory and Other Factors
Affecting Our Wholesale Energy Operations -- Price Volatility."
Other Regulatory Factors. Pursuant to the Legislation, 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 Legislation, over the market value
of those assets) and its regulatory assets related to generation. The
Legislation prescribes specific methods for determining the amount of stranded
costs and the details for their recovery. However, during the base rate freeze
period from 1999 through 2001, earnings above the utility's authorized rate of
return formula may be 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 may be
redirected to generation assets for regulatory purposes during that period. The
Legislation also provides for Reliant Energy HL&P, or a special purpose entity,
to issue securitization bonds for the recovery of generation related regulatory
assets and a portion of stranded costs. Any stranded costs not recovered through
the sale of securitization bonds may be recovered through a non-bypassable
charge to transmission and distribution customers. For additional information
regarding these securitization bonds, please read "-- Liquidity and Capital
Resources -- Future Sources and Uses of Cash -- Securitization."
The Texas Utility Commission recently stated on record that it would
consider requiring electric utilities to reverse the amount of redirected
depreciation and accelerated depreciation previously taken if in its estimation
the utility has overmitigated its stranded costs. The reversal could occur
through a lower rate for the transmission and distribution utility and/or
through credits contained in the transmission and distribution utility's rate.
Any order requiring the reversal of these amounts would likely be included in
the Texas Utility Commission proceeding establishing the initial rate of the
transmission and distribution utility or in the case of our Electric Operations
segment, the Wires Case. We do not expect the final transmission and
distribution rate in the Wires Case to be established until August 2001. For
more information regarding the Wires Case, see "Business -- Regulation -- State
and Local Regulations -- Texas -- Electric Operations -- Rate Case."
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At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's
previously regulated electric generation assets pursuant to SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" (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, we 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. We determined that $797 million of electric generation assets were
impaired as of June 30, 1999. Of these amounts, $745 million related to the
South Texas Project and $52 million related to two gas-fired generation plants.
The Legislation provides for recovery of this impairment through regulated cash
flows during the transition period and through non-bypassable charges to
transmission and distribution customers. As such, a regulatory asset has been
recorded for an amount equal to the impairment loss. We recorded amortization
expense related to the recoverable impaired plant costs and other assets created
from discontinuing regulatory accounting of $221 million in the third and fourth
quarters of 1999 and $329 million in 2000. We expect to fully amortize this
regulatory asset as it is recovered from regulated cash flows 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 Legislation) 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 Legislation) will be collected through future non-bypassable
charges. Any over-mitigation of stranded costs may be refunded through future
non-bypassable 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. Because generally accepted
accounting principles require us to estimate fair market values on a
plant-by-plant basis in advance of the final reconciliation, the financial
impacts of the Legislation with respect to the final determination of stranded
costs in 2004 are subject to material changes. Factors affecting such change may
include estimation risk, uncertainty of future energy and commodity prices and
the economic lives of the plants. If events occur that make the recovery of all
or a portion of the regulatory assets associated with the generation plant
impairment loss and other assets created from discontinuance of regulatory
accounting pursuant to the Legislation no longer probable, we will write off the
corresponding balance of these assets as a non-cash 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.
In accordance with the Legislation, beginning on January 1, 2002, and
ending at December 31, 2003, 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 costs
true-up. 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.
Since the time of our original impairment calculation in June 1999 when we
discontinued application of SFAS No. 71 for our generation operations, natural
gas prices have risen 295% from June 1999 to December 31, 2000 resulting in
increases in estimated market prices for power during 2002 and 2003. Generally,
for Reliant Energy HL&P's generation portfolio, sustained increases in natural
gas prices result in an increase in the fair value of Reliant Energy HL&P's
generation portfolio, due to our mix of lower variable cost of electric
generation. Therefore, as electric power prices increase, the amount of our
estimated stranded costs decline and the estimate of our 2002 and 2003 capacity
true-up amounts which may be owed to customers increases.
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For additional information regarding the impairment of regulatory assets
and electric generating plant and equipment as well as the recovery of stranded
costs, please read Note 4(a) to our consolidated financial statements. For
additional information regarding our filings to recover under-recovered fuel
costs, please read Note 4(d) to our consolidated financial statements.
Other. For additional information regarding litigation over franchise
fees, please read Note 14(g) to our consolidated financial statements.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY
OPERATIONS
Competition. As of December 31, 2000, our Wholesale Energy business
segment owned and operated 9,231 MW of electric generation assets that serve
wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent
regions of the United States and the states of Florida and Texas. Competitive
factors affecting the results of operations of these generation assets include
new market entrants and construction by others of more efficient generation
assets.
The wholesale power industry has numerous competitors, some of which may
have more operating experience, more acquisition and development experience,
larger staffs and/or greater financial resources than we do. Like us, many of
our competitors are seeking attractive opportunities to acquire or develop power
generation facilities, both in the United States and abroad. This competition
may adversely affect our ability to make investments or acquisitions.
Also, industry restructuring requires or encourages the disaggregation of
many vertically-integrated utilities into separate generation, transmission and
distribution, and retail businesses. As a result, a significant number of
additional competitors could become active in the wholesale power generation
segment of our industry.
Furthermore, other competitors operate power generation projects in the
regions where we have invested in electric generation assets. While demand for
electric energy services is generally increasing throughout the United States,
the rate of construction and development of new, more efficient electric
generation facilities may exceed increases in demand in some regional electric
markets. Although local permitting and siting issues often reduce the risk of a
rapid growth in supply of generation capacity in any particular region, projects
are likely to be built over time. The commencement of commercial operation of
these new facilities in the regional markets where we have facilities will
likely increase the competitiveness of the wholesale power market in those
regions, which could have a material effect on our business and lower the value
of some of our electric generation assets.
Finally, our trading, marketing, power origination and risk management
operations compete with other energy merchants based on the ability to aggregate
supplies at competitive prices from different sources and locations and to
efficiently utilize transportation from third-party pipelines and transmission
from electric utilities. These operations also compete against other energy
marketers on the basis of their relative skills, financial position and access
to credit sources. This competitive factor reflects the tendency of energy
customers, wholesale energy suppliers and transporters to seek financial
guarantees and other assurances that their energy contracts will be satisfied.
As pricing information becomes increasingly available in the energy trading and
marketing business and as deregulation in the electricity markets continues to
accelerate, we anticipate that our trading, marketing, power origination and
risk management operations will experience greater competition and downward
pressure on per-unit profit margins.
Regulation. The regulatory environment applicable to the electric power
industry has recently undergone substantial changes as a result of restructuring
initiatives at both the state and federal levels. These initiatives have had a
significant impact on the nature of the industry and the manner in which its
participants conduct their business. Our Wholesale Energy segment has targeted
the deregulating wholesale and retail segments of the electric power industry
created by these initiatives. These changes are ongoing and we cannot predict
the future development of deregulation in these markets or the ultimate effect
that this changing regulatory environment will have on our business.
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Moreover, existing regulations may be revised or reinterpreted, new laws
and regulations may be adopted or become applicable to us or our facilities, and
future changes in laws and regulations may have a detrimental effect on our
business. Certain restructured markets, particularly California, have recently
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 (please read "-- California" below), proposals have been
made by governmental agencies and/or other interested parties to slow the pace
of deregulation or to re-regulate areas of these markets that have previously
been deregulated. If the current trend towards competitive restructuring of the
wholesale and retail power markets is reversed, discontinued or delayed, the
business growth prospects of our Wholesale Energy segment would be slowed and
the financial outlook for our existing positions could be impacted.
If RTOs are established as envisioned by FERC Order 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 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. For additional information
regarding FERC Order 2000 affecting these RTOs, please read
"Business -- Regulation -- Federal Energy Regulatory Commission" in Item 1 of
this Form 10-K.
Price Volatility. Our Wholesale Energy business segment sells electricity
from our non-Texas power generation facilities into the spot market or other
competitive power markets or on a contractual basis. Our Wholesale Energy
business segment is not guaranteed any rate of return on our capital investments
through mandated 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 and other competitive markets. These market prices may
fluctuate substantially over relatively short periods of time. In addition, the
FERC, which has jurisdiction over wholesale power rates, as well as independent
system operators that oversee some of these markets, may impose price
limitations, bidding rules and other mechanisms to address some of the
volatility in these markets. 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.
These factors could have an adverse impact on our revenues and results of
operations.
Volatility in market prices for fuel and electricity may result from:
- weather conditions,
- seasonality,
- electricity usage,
- illiquid markets,
- transmission or transportation constraints or inefficiencies,
- availability of competitively priced alternative energy sources,
- demand for energy commodities,
- natural gas, crude oil and refined products, and coal production levels,
- natural disasters, wars, embargoes and other catastrophic events, and
- federal, state and foreign energy and environmental regulation and
legislation.
Trading, Marketing, Power Origination and Risk Management Operations. To
lower our Wholesale Energy business segment's financial exposure related to
commodity price fluctuations, its trading, marketing, power origination and risk
management operations routinely enter into contracts to hedge a portion of its
purchase and sale commitments, weather positions, fuel requirements and
inventories of natural gas, coal, crude oil and refined products, and other
commodities. As part of this strategy, our Wholesale Energy business segment
routinely utilizes fixed-price forward physical purchase and sales contracts,
futures, financial swaps
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and option contracts traded in the over-the-counter markets or on exchanges.
However, our Wholesale Energy business segment does not expect to cover the
entire exposure of its assets or its positions to market price volatility and
the coverage will vary over time. To the extent our Wholesale Energy business
segment has unhedged positions, fluctuating commodity prices can impact our
financial results and financial position, either favorably or unfavorably.
At times, our Wholesale Energy business segment has open trading positions
in the market, within established guidelines, resulting from the management of
its trading portfolio. To the extent open trading positions exist, fluctuating
commodity prices can impact our financial results and financial position, either
favorably or unfavorably.
The risk management procedures our Wholesale Energy business segment has 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. Although our Wholesale Energy business segment devotes a
considerable amount of management effort to these issues, their outcome is
uncertain.
Our trading, marketing, power origination and risk management operations
are also exposed to the risk that counterparties who owe it money or physical
commodities, such as energy or gas, as a result of market transactions will not
perform their obligations. Should the counterparties to these arrangements fail
to perform, our trading, marketing, power origination and risk management
operations might be forced to acquire alternative hedging arrangements or
replace the underlying commitment at then-current market prices. In this event,
our trading, marketing, power origination and risk management operations might
incur additional losses to the extent of amounts, if any, already paid to the
counterparties.
California. During the summer and fall of 2000, 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,
decreases in net electric imports, structural market flaws including
over-reliance on the electric spot market, and limitations on supply as a result
of maintenance and other outages. Although wholesale prices increased,
California's deregulation legislation kept retail rates frozen below 1996
levels. This caused two of California's public utilities, which are our
customers based on our deliveries to the Cal PX and the Cal ISO, to amass
billions of dollars of uncollected wholesale power costs and to ultimately
default in January and February 2001 on payments owed for wholesale power
purchased through the Cal PX and from the Cal ISO.
As of December 31, 2000, we were owed $101 million by the Cal PX and $181
million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax
provision of $39 million against receivable balances related to energy sales in
the California market. From January 1, 2001 through February 28, 2001, we have
collected $105 million of these receivable balances. As of March 1, 2001, we
were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and
California Energy Resources Scheduling for energy sales in the California
wholesale market from the fourth quarter of 2000 through February 28, 2001.
Management will continue to assess the collectibility of these receivables based
on further developments affecting the California electricity market and the
market participants described herein. Additional provisions to the allowance may
be warranted in the future.
In response to the filing of a number of complaints challenging the level
of wholesale prices, the FERC initiated a staff investigation and issued an
order on December 15, 2000 implementing a series of wholesale market reforms,
including an interim price review procedure for prices above a $150/MWh
"breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not
prohibit sales above the "breakpoint," but the seller is subject to weekly
reporting and monitoring requirements. For each reported transaction, potential
refund liability extends for a period of 60 days following the date any such
transaction is reported to the FERC. On March 9, 2001, the FERC issued a further
order establishing a proxy market clearing price of $273/MWh for January 2001,
and on March 16, 2001 the FERC issued a further order adjusting the proxy market
clearing price to $430/MWh for February 2001. New market monitoring and
mitigation measures to replace the $150/MWh breakpoint and reporting obligation
are being developed by the FERC to take effect on May 1, 2001.
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In the FERC's March 9 and March 16 orders, the FERC outlined criteria for
determining amounts subject to possible refund based on the proxy market
clearing price for January and February 2001 and indicated that approximately
$12 million of the $125 million charged by us in January 2001 in California to
the Cal ISO and the Cal PX and approximately $7 million of the $47 million
charged by us in February 2001 in California to the Cal ISO and the Cal PX were
subject to possible refunds. In the March 9 and March 16 orders, the FERC set
forth procedures for challenging possible refund obligations. Because we believe
that there is cost or other justification for prices charged above the proxy
market clearing prices established in the March 9 and March 16 orders, we intend
to pursue such a challenge with respect to our potential refund amounts
identified in such orders. Any refunds we may ultimately be obligated to pay are
to be credited against unpaid amounts owed to us for our sales in the Cal PX or
to the Cal ISO. The December 15 order established that a refund condition would
be in place for the period beginning October 2, 2000 through December 31, 2002.
The December 15 order also eliminated the requirement that California's public
utilities sell all of their generation into and purchase all of their power from
the Cal PX and directed that the Cal PX wholesale tariffs be terminated
effective April 2001. The Cal PX has since suspended its day-ahead and day-of
markets and filed for bankruptcy protection on March 9, 2001. Motions for
rehearing have been filed on a number of issues related to the December 15 order
and such motions are still pending before the FERC.
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 Public
Utilities Commission, the California Electricity Oversight Board, the California
Bureau of State Audits and the California Office of the Attorney General all
have separate ongoing investigations into the high prices and their causes. None
of these investigations have been completed and no findings have been made in
connection with any of them.
Despite the market restructuring ordered under the December 15 order, the
California public utilities have continued to accrue unrecovered wholesale
costs. As a result, the credit ratings of two of these public utilities were
severely downgraded to below investment grade in January 2001. As their credit
lines became unavailable, the two utilities defaulted on payments due to the Cal
PX and the Cal ISO, which operate financially as pass-through entities,
coordinating payments from buyers and sellers of electricity. As a result, the
Cal PX and Cal ISO were not able to pay final invoices to market participants
totaling over $1 billion.
The default of two of California's public utilities on amounts owed the Cal
PX and the Cal ISO for purchased power has further exacerbated the current
crisis in the California wholesale markets and resulted in substantial
uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's
efforts to recover the available collateral of the utilities, in the form of
block forward contracts, have been frustrated by the emergency acts of
California's Governor, who seized control of the contracts upon the expiration
of temporary restraining orders prohibiting such action. Although obligated to
pay reasonable value for the contracts, the state of California has not yet made
any payment for the contracts. Various actions have been filed challenging the
Governor's ability to seize these contracts.
Upon the default of the two utilities of amounts due to the Cal PX, the Cal
PX issued "charge-backs" allocating the utilities' defaults to the other market
participants. Proceedings were brought both in federal court and at the FERC
seeking a suspension of the charge-backs and challenging the reasonableness of
the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction
suspending any of its charge-back activities in order to allow the FERC to
address the charge-back issues. Amounts owed to us were debited in invoices by
the Cal PX for charge-backs in the amount of $29 million and, on February 14,
2001, we filed our own lawsuit against the Cal PX in the United States District
Court for the Central District of California, seeking a recovery of those
amounts and a stay of any further charge-backs by the Cal PX. The filing of
bankruptcy by the Cal PX will automatically stay for some period the various
court and administrative cases against the Cal PX.
The two defaulting utilities have both filed lawsuits challenging the
refusal of state regulators to allow wholesale power costs to be passed through
to retail customers under the "filed rate doctrine." The filed rate doctrine
provides that wholesale power costs approved by the FERC are entitled to be
recovered through rates.
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Additionally, to address the failing financial condition of the two defaulting
utilities and the utilities' potential bankruptcy, the California Legislature
passed emergency legislation, effective January 18, 2001 and February 2, 2001,
appropriating funds to be used by the CDWR for the purchase of wholesale
electricity on behalf of the utilities and authorizing the sale of bonds to fund
future purchases under long-term power contracts with wholesale generators. The
CDWR began the process of soliciting bids from generators for long-term
contracts and continued the purchasing of short-term power contracts. No bonds
have yet been issued by the CDWR to support long-term power purchases or to
provide credit support for short-term purchases.
As noted above, two of California's public utilities have defaulted in
their payment obligations to the Cal PX and the Cal ISO as a result of the
refusal of state regulators to allow them to recover their wholesale power
costs. This refusal by state regulators has also caused the utilities to default
on numerous other financial obligations, which could result in either the
voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing
would result in further post-petition purchases of wholesale electricity being
considered administrative expenses of the debtor, a substantial delay could be
experienced in the payment of pre-petition receivables pending the confirmation
of a reorganization plan. The California Legislature is currently considering
legislation under which a state entity would be formed to purchase and operate a
substantial share of the transmission lines in California in an effort to
provide cash to the utilities and thereby avoid potential bankruptcy filings by
the utilities. A number of the creditors for the two California public utilities
have indicated, however, that unless California moves quickly with such a plan,
an involuntary bankruptcy filing may be made by one or more of such creditors.
Because California's power reserves remain at low levels, in part as a
result of the lack of creditworthy buyers of power given the defaults of the
California utilities, the Cal ISO has relied on emergency dispatch orders
requiring generators to provide at the Cal ISO's direction all power not already
under contract. The power supplied to the Cal ISO has been used to meet the
needs of the customers of the utilities, even though two of those utilities do
not have the credit required to receive such power and may be unable to pay for
it. We have contested the obligation to provide power under these circumstances.
The Cal ISO sought a temporary restraining order compelling us to continue to
comply with the emergency dispatch orders despite the utilities' defaults.
Although the payment issue is still disputed, on February 21, 2001, we and the
CDWR entered into a contract expiring March 23, 2001 for the purchase of all of
our available capacity not already under contract and the litigation has been
temporarily stayed. The CDWR is current in its payments under this contract, but
we are still owed $108 million for power provided in compliance with the
emergency dispatch orders for the six weeks prior to the agreement. Depending on
the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin
us from ceasing power deliveries to the Cal ISO, we may be forced to continue
selling power without the guarantee of payment.
Additionally, we are seeking a prompt FERC determination that the Cal ISO
is not complying with the credit provisions of its tariff and a related order of
the FERC issued on February 14, 2001, requiring the Cal ISO not to make
purchases in the real time market unless a creditworthy purchaser is responsible
for such purchases.
For additional information regarding the situation in California, please
read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest
Region" and "Business -- Regulation -- State and Local
Regulations -- California" in Item 1 of this Form 10-K, "-- Results of
Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as
well as Notes 14(g) and 14(h) to our consolidated financial statements.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY
OPERATIONS
Competition. The European energy market is highly competitive. In
addition, over the next several years, we expect an increasing consolidation of
the participants in the European generating market.
Our European wholesale operations compete in the Netherlands, primarily
against the three other largest Dutch generating companies, various cogenerators
of electric power, various alternate sources of power and non-Dutch generators
of electric power, primarily from France and Germany. In 2000, UNA and the three
other largest Dutch generating companies supplied approximately 50% of the
electricity consumed in the
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Netherlands. Smaller Dutch producers supplied about 25% of the consumed
electricity, and the remainder was imported. At present, the Dutch electricity
system has 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 used to import
electricity from France, but a larger portion of Dutch electricity imports comes
from Germany.
Our European trading and marketing operations will also be subject to
increasing levels of competition. As of December 31, 2000, there were 32 trading
and marketing companies registered with the Amsterdam Power Exchange.
Competition among power generators for customers is intense, and we expect
competition to increase with the deregulation of the market. Please read
"-- Regulation." The primary elements of competition affecting both the
generation and trading and marketing operations of our European Energy business
segment are price, credit support, and supply and delivery reliability.
Deregulation. The Dutch electricity market was opened to limited wholesale
and retail competition on January 1, 1999 as retail competition for large
industrial customers began. The Dutch wholesale electric market was completely
opened to competition on January 1, 2001. Consistent with our expectations at
the time we made the acquisition, we anticipate that our European Energy
business segment may experience a significant decline in gross margin in 2001
attributable to the deregulation of the market and termination of an agreement
with the other Dutch generators and the Dutch distributors. The next customer
segment, composed primarily of commercial customers, will be liberalized by
2002. The remainder of the market, mainly residential, will be open to
competition by 2003. The timing of these market openings is subject to change,
however, at the discretion of the Dutch Minister of Economic Affairs. In
addition, the results of our European Energy segment will be negatively impacted
beginning in 2002 due to the imposition of a standard Dutch corporate income tax
rate, which is currently 35%, on the income of UNA. In 2000 and prior years,
UNA's Dutch corporate income tax rate was zero percent.
Other. Another factor that could have a significant impact on the Dutch
energy industry, including the operations of our European Energy business
segment, is the ultimate resolution of stranded costs issues in the Netherlands.
Prior to 2001, UNA and the other Dutch generators sold their generating output
through the coordinating body for the Dutch electricity generating sector, B.V.
Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has
incurred "stranded" costs as a result of, among other things, a perceived need
to cover anticipated shortages in energy production supply. NEA stranded costs
consist primarily of investments in alternative energy sources and fuel and
power purchase contracts currently estimated to be uneconomical. Legislation has
been approved by the Dutch parliament which would transfer the liability for the
stranded costs from NEA to its four shareholders, one of which is UNA. For
information regarding this legislation, please read Note 14(i) to our
consolidated financial statements.
In connection with our acquisition of UNA, the selling shareholders of UNA
agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG
1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar
as of December 31, 2000), which may be increased in some circumstances at our
option up to NLG 1.9 billion ($812 million). Of the total consideration we paid
for the shares of UNA, NLG 900 million ($385 million) has been placed by the
selling shareholders under the direction of the Dutch Minister of Economic
Affairs in an escrow account to secure the indemnity obligations by the former
shareholders of UNA. Although our management believes that the indemnity
provision will be sufficient to fully satisfy UNA's ultimate share of any
stranded costs obligation, this judgment is based on numerous assumptions
regarding the ultimate outcome and timing of the resolution of the stranded cost
issue, the former shareholders' timely performance of their obligations under
the indemnity arrangement, and the amount of stranded costs, which at present is
not determinable. Any shortfall in the indemnity provision could have a material
adverse effect on our results of operations.
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
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U.S. dollar during 2000 negatively impacted U.S. dollar net income in the amount
of approximately $8 million.
Impact of Currency Fluctuations on Company Earnings. For information about
our exposure through our investment in Europe to losses resulting from
fluctuations in currency rates, please read "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this Form 10-K.
COMPETITIVE AND OTHER FACTORS AFFECTING RERC 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.
Pipelines and Gathering. Our Pipelines and Gathering 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 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
to be, negatively impacted from the recent price levels and the tightening of
supply. 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.
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 its contract with Laclede, which
has been under an annual evergreen term provision since 1999. In the event we
are not able to renegotiate a long-term extension to the contract with Laclede,
and Laclede engages another pipeline for the transportation services it
currently obtains from us, the operating and financial results of our Pipelines
and Gathering business segment would be materially adversely affected.
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.
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INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT
For information on our indexed debt securities and our investment in AOL
Time Warner common stock, please read "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated
financial statements.
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(g) 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 Operations
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 Texas and the
Mid-Atlantic region. We currently estimate that up to $534 million will be
required to comply with the requirements through the end of 2003, with an
estimated $215 million to be incurred in 2001. The Texas regulations require
additional reductions that must be completed by March 2007. Estimates for the
Texas units for the period 2004 through 2007 have not been defined, but could be
up to $230 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 Legislation created a program
mandating air emissions reductions for some generating facilities of our
Electric Operations segment. The Legislation provides for stranded costs
recovery for costs associated with this obligation incurred before May 1, 2003.
For additional information regarding the Legislation, please read Note 4(a) to
our consolidated financial statements. Additional NOx emission controls for our
generating units located in California may result in expenditures of up to $30
million through 2002. 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(g) to our
consolidated financial statements and Note 9(c) to RERC's 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, 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.
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OTHER CONTINGENCIES
For a description of other legal and regulatory proceedings affecting us,
please read Notes 4 and 14 to our consolidated financial statements and Note 9
to RERC's consolidated financial statements.
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES
o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(f) Regulatory Assets.
The Company applies the accounting policies established in Statement of
Financial Accounting Standards (SFAS) No. 71 (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
(Legislation), 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, 1999 and 2000.
DECEMBER 31,
---------------
1999 2000
------ ------
(IN MILLIONS)
Recoverable impaired plant costs, net....................... $ 587 $ 281
Recoverable electric generation related regulatory assets,
net....................................................... 952 1,385
Regulatory tax liability, net............................... (45) (49)
Unamortized loss on reacquired debt......................... 69 66
Other long-term assets/liabilities.......................... (14) 6
------ ------
Total............................................. $1,549 $1,689
====== ======
Included in the above table are $191 million and $237 million of regulatory
liabilities recorded as other long-term liabilities in the Company's
Consolidated Balance Sheets as of December 31, 1999 and 2000, respectively,
which primarily relate to the recovery of fuel costs as of December 31, 1999,
and gains on nuclear decommissioning trust funds, regulatory tax liabilities and
excess deferred income taxes as of December 31, 1999 and 2000.
Under a "deferred accounting" plan authorized by the Public Utility
Commission of Texas (Texas Utility Commission), Electric Operations was
permitted for regulatory purposes to accrue carrying costs in the form of
allowance for funds used during construction (AFUDC) on its investment in the
South Texas Project Electric Generating Station (South Texas Project) and to
defer and capitalize depreciation and other operating costs on its investment
after commercial operation until these costs were reflected in rates. In
addition, the Texas Utility Commission authorized Electric Operations to defer
allowable costs (including return) for future recovery. Pursuant to SFAS No. 92,
"Regulated Enterprises -- Accounting for Phase-in Plans," the Company deferred
these costs. These costs are included in recoverable electric generation related
regulatory assets. The amortization of all deferred plant costs (which totaled
$26 million for 1998) is included in the Company's Statements of Consolidated
Operations as depreciation and amortization expense. Pursuant to the
Legislation, see Note 4(a), the Company discontinued amortizing deferred plant
costs effective January 1, 1999.
In 1998, 1999 and 2000, the Company, as permitted by the 1995 rate case
settlement (Rate Case Settlement), also amortized $4 million, $22 million and
$11 million, respectively, of its investment in lignite reserves associated with
a canceled generating station. The investment in these reserves was fully
amortized during 2000.
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For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets and the related amortization
during 1999 and 2000, see Notes 2(g) and 4(a).
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,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" (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.
o (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 megawatts (MW). With the exception of development entities
that were sold to another subsidiary of the Company in July 2000, the assets of
the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings,
LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion,
subject to post-closing adjustments which management does not believe will be
material. The Company accounted for the acquisition as a purchase with assets
and liabilities of REMA reflected at their estimated fair values. On a
preliminary basis, the Company's fair value adjustments related to the
acquisition primarily included adjustments in property, plant and equipment, air
emissions regulatory allowances, 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
excess of the purchase price over the fair value of net assets acquired of $7
million was recorded as goodwill and is being amortized over 35 years. The
Company expects to finalize these fair value adjustments no later than May 2001,
based on valuation reports of property, plant and equipment and intangible
assets, and does not anticipate additional material modifications to the
preliminary adjustments. Funds for the acquisition of REMA were made available
through commercial paper borrowings by a finance subsidiary, which borrowings
were supported by bank credit facilities.
The net purchase price of REMA was allocated and the fair value adjustments
to the seller's book value are as follows (in millions):
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
Current assets.............................................. $ 75 $ (37)
Property, plant and equipment............................... 1,941 670
Goodwill.................................................... 7 (144)
Other intangibles........................................... 153 (10)
Other assets................................................ 4 (4)
Current liabilities......................................... (45) (8)
Other liabilities........................................... (38) (14)
------ -----
$2,097 $ 453
====== =====
Adjustments to property, plant and equipment, other intangibles, which
includes air emissions regulatory allowances, and environmental reserves
included in other liabilities are based primarily on valuation reports prepared
by independent appraisers and consultants.
In August 2000, the Company entered into separate sale/leaseback
transactions with each of three owner-lessors for the Company's 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, the Company
leases an interest in each facility from each owner-lessor under a facility
lease agreement. As consideration for
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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
commercial paper referred to above.
The Company's results of operations include the results of REMA only for
the period beginning May 12, 2000. Prior to November 24, 1999, the acquired
entities' operations were fully integrated with, and their results of operations
were consolidated into, the regulated electric utility operations of a prior
owner of the facilities. In addition, prior to November 24, 1999, the electric
output of the facilities was sold based on rates set by regulatory authorities
and is not indicative of REMA's future results. 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 prior to November 24, 1999
would not be meaningful since historical financial results of the business and
the revenue generating activities underlying that period as described above 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.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000
------------------- -------------------
UNAUDITED UNAUDITED
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues............................................. $15,223 $15,253 $29,339 $29,506
Income from continuing operations before
extraordinary items................................ 1,674 1,664 771 762
Net income attributable to common stockholders....... 1,482 1,472 447 438
Basic earnings per share from continuing operations
before extraordinary items......................... 5.87 5.84 2.71 2.68
Diluted earnings per share from continuing operations
before extraordinary items......................... 5.85 5.82 2.68 2.65
Basic earnings per share............................. 5.20 5.16 1.57 1.54
Diluted earnings per share........................... 5.18 5.15 1.56 1.53
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) N.V. UNA.
Effective October 7, 1999, the Company acquired N.V. UNA (UNA), 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. The business purchase obligation was recorded in the Company's
Consolidated Balance Sheet as of December 31, 1999, based on the exchange rate
on December 31, 1999, of 2.19 NLG per U.S. dollar. A portion ($596 million) of
the business purchase obligation was classified as a non-current liability, as
this portion of the obligation was financed with a three-year term loan facility
obtained in the first quarter of 2000.
The Company recorded the UNA acquisition under the purchase method of
accounting, with assets and liabilities of UNA reflected at their estimated fair
values. As outlined in the table below, the Company's fair value adjustments
related to the acquisition of UNA 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
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shareholders agreed to reimburse UNA for some obligations incurred prior to the
purchase of UNA. Adjustments to property, plant and equipment are based
primarily on valuation reports prepared by independent appraisers and
consultants. The excess of the purchase price over the fair value of net assets
acquired of $897 million was recorded as goodwill and will be amortized on a
straight-line basis over 30 years. The Company finalized these fair value
adjustments during September 2000. The Company finalized a severance plan (UNA
Plan) in connection with the UNA acquisition in September 2000 (commitment date)
and in accordance with EITF 95-3 "Recognition of Liabilities in Connection with
a Purchase Business Combination," recorded this liability of $19 million in the
third quarter of 2000. Payments under the UNA Plan will be primarily made in
mid-2001.
In connection with the acquisition of UNA, the Company developed a
comprehensive business process reengineering and employee severance plan
intended to make UNA competitive in the deregulated Dutch electricity market
that began January 1, 2001. The UNA Plan's initial conceptual formulation was
initiated prior to the acquisition of UNA in October 1999. The finalization of
the UNA Plan was approved and completed in September 2000. The Company
identified 195 employees who will be involuntarily terminated in UNA'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 UNA Plan that they
are subject to involuntary termination and that the majority of terminations
will occur over a period not to exceed twelve months from the date of
finalization of the UNA Plan. The termination benefits under the UNA Plan are
governed by UNA's Social Plan, a collective bargaining agreement between UNA 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 UNA 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 UNA. The
Company is currently executing the UNA Plan as of the date of these Consolidated
Financial Statements.
The net purchase price of UNA was allocated and the fair value adjustments
to the seller's book value are as follows (in millions):
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
Current assets.............................................. $ 229 $ 19
Property, plant and equipment............................... 1,899 719
Goodwill.................................................... 897 897
Current liabilities......................................... (336) --
Deferred taxes.............................................. (81) (81)
Long-term debt.............................................. (422) (87)
Other long-term liabilities................................. (244) (35)
------ ------
$1,942 $1,432
====== ======
The following table presents selected actual financial information for 1998
and 1999, and unaudited pro forma information for 1998 and 1999, as if the
acquisition of UNA had occurred on January 1, 1998 and 1999, respectively. The
unaudited 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 UNA had occurred on January 1, 1998 and 1999, as
applicable. Purchase related adjustments to results of operations include
amortization of goodwill,
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interest expense and the effects on depreciation and amortization of the
assessed fair value of some of UNA's net assets and liabilities.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1999
------------------- -------------------
UNAUDITED UNAUDITED
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues............................................. $11,230 $12,062 $15,223 $15,704
Income from continuing operations before
extraordinary item................................. (278) (227) 1,674 1,648
Net (loss) income attributable to common
stockholders....................................... (141) (90) 1,482 1,455
Basic earnings per share from continuing operations
before extraordinary item.......................... (0.98) (0.80) 5.87 5.78
Diluted earnings per share from continuing operations
before extraordinary item.......................... (0.98) (0.80) 5.85 5.76
Basic earnings per share............................. (0.50) (0.32) 5.20 5.11
Diluted earnings per share........................... (0.50) (0.32) 5.18 5.09
o (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 Legislation, which
substantially amended the regulatory structure governing electric utilities in
Texas in order to allow retail electric competition. Retail pilot projects for
up to 5% of each utility's load in all customer classes will begin in June 2001,
and retail electric competition for all other customers will begin on January 1,
2002. In preparation for that competition, the Company expects to make
significant changes in the electric utility operations it conducts through its
electric utility division, Reliant Energy HL&P. In addition, the Legislation
requires the Texas Utility Commission to issue a number of new rules and
determinations in implementing the Legislation.
The Legislation defines the process for competition and creates a
transition period during which most utility rates are frozen at rates not in
excess of their present levels. The Legislation provides for utilities to
recover their generation related stranded costs and regulatory assets (as
defined in the Legislation).
Retail Choice. Under the Legislation, on January 1, 2002, retail customers
of most investor owned electric utilities in Texas will be entitled to purchase
their electricity from any of a number of "retail electric providers," which
will have been certified by the Texas Utility Commission. Retail electric
providers will not own or operate generation assets and their sales rates will
not be subject to traditional cost-of-service rate regulation. Retail electric
providers that are affiliates of electric utilities may compete substantially
statewide for these sales, but rates 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 will
prescribe regulations governing quality, reliability and other aspects of
service from retail electric providers. Transactions between the regulated
utility and its current and future competitive affiliates are subject to
regulatory scrutiny and must comply with a code of conduct established by the
Texas Utility Commission. The code of conduct governs interactions among
employees of regulated and current and future unregulated affiliates as well as
the exchange of information between these affiliates. The Company intends to
compete in the Texas retail market and, as a result, has certified two of its
subsidiaries as retail electric providers.
Unbundling. By January 1, 2002, electric utilities in Texas such as
Reliant Energy HL&P will restructure their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Legislation, the Company submitted a plan in January 2000
that was later amended 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
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business will continue to be subject to cost-of-service rate regulation and will
be responsible for the delivery of electricity to retail customers.
Generation. Power generators will sell electric energy to wholesale
purchasers, including retail electric providers, at unregulated rates beginning
January 1, 2002. To facilitate a competitive market, each power generation
company affiliated with a transmission and distribution utility will be required
to sell at auction 15% of the output of its installed generating capacity. The
first auction will be held on or before September 1, 2001 for power delivered
after January 1, 2002. This obligation continues until January 1, 2007 unless
before that date the Texas Utility Commission determines 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. The Legislation also creates a program mandating
air emissions reductions for non-permitted generating facilities. The Company
anticipates that any stranded costs associated with this obligation incurred
before May 1, 2003 will be recoverable through the stranded costs recovery
mechanisms contained in the Legislation.
Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will
be frozen until January 1, 2002. Pursuant to Texas Utility Commission
regulations, effective January 1, 2002, retail rates charged to residential and
small commercial customers by the utility's affiliated retail electric provider
will be reduced by 6% from the average rates (on a bundled basis) in effect on
January 1, 1999 (adjusted for fuel charges). That reduced rate will be known as
the "price to beat" and will be 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 available to eligible consumers until January 1, 2007.
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 Legislation) over the market value of those assets) and its
regulatory assets related to generation. The Legislation prescribes specific
methods for determining the amount of stranded costs and the details for their
recovery. However, during the base rate freeze period from 1999 through 2001,
earnings above the utility's authorized return formula will be 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 may be redirected to generation assets for
regulatory purposes during that period.
The Texas Utility Commission has recently stated on record that it would
consider requiring electric utilities to reverse the amount of redirected
depreciation and accelerated depreciation previously taken if in its estimation
the utility has overmitigated its stranded costs. The reversal could occur
through a lower rate for the transmission and distribution utility and/or
through credits contained in the transmission and distribution utility's rate.
Any order requiring the reversal of these amounts would likely be included in
the Texas Utility Commission proceeding establishing the initial rate of the
transmission and distribution utility. The Company does not expect the final
Reliant Energy HL&P transmission and distribution rate to be established until
August 2001. For information regarding redirected depreciation, see "Accounting"
in this Note 4(a).
The Legislation provides for Reliant Energy HL&P, or a special purpose
entity, to issue securitization bonds for the recovery of generation related
regulatory assets and a portion of stranded costs. These bonds will be sold to
third parties and will be amortized through non-bypassable charges to
transmission and distribution customers. Any stranded costs not recovered
through the securitization bonds will be recovered through a non-bypassable
charge to transmission and distribution customers. 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 non-bypassable charge to transmission and distribution customers. For
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further discussion of the effect of the Business Separation Plan on funding of
the nuclear decommissioning trust fund, see Note 4(b).
In May 2000, the Texas Utility Commission issued a financing order to the
Company authorizing the issuance of transition bonds in an amount not to exceed
$740 million plus actual up-front qualified costs. Payments on the transition
bonds will be made out of funds derived from non-bypassable transition charges
to Reliant Energy HL&P's transmission and distribution customers. The offering
of the transition bonds will be registered under the Securities Act of 1933 and
is expected to be consummated during 2001.
Capacity Auction True-up. In accordance with the Legislation, beginning on
January 1, 2002, and ending when the true-up proceeding is completed, 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 costs 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. For information
regarding the effect of the Business Separation Plan on the generation capacity
auctions, see Note 4(b).
Accounting. Historically, Reliant Energy HL&P has applied the accounting
policies established in SFAS No. 71. In general, SFAS No. 71 permits a company
with cost-based rates to defer some costs that would otherwise be expensed to
the extent that it meets the following requirements: (a) its rates are regulated
by a third-party; (b) its rates are cost-based; and (c) there exists a
reasonable assumption that all costs will be recoverable from customers through
rates. When a company determines that it no longer meets the requirements of
SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write
off regulatory assets and liabilities unless some form of recovery continues
through rates established and collected from remaining regulated operations. In
addition, such company is required to determine any impairment to the carrying
costs of deregulated plant and inventory assets in accordance with SFAS No. 121.
In July 1997, the EITF reached a consensus on Issue No. 97-4, "Deregulation
of the Pricing of Electricity -- Issues Related to the Application of FASB
Statements No. 71, Accounting for the Effects of Certain Types of Regulation,
and No. 101, Regulated Enterprises Accounting for the Discontinuation of
Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded
that a company should no longer apply SFAS No. 71 to a segment which is subject
to a deregulation plan at the time the deregulation legislation or enabling rate
order contains sufficient detail for the utility to reasonably determine how the
plan will affect the segment to be deregulated. In addition, EITF No. 97-4
requires that regulatory assets and liabilities be allocated to the applicable
portion of the electric utility from which the source of the regulated cash
flows will be derived.
The Company believes that the Legislation provides sufficient detail
regarding the deregulation of the Company's electric generation operations to
require it to discontinue the use of SFAS No. 71 for those operations. 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 Legislation 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 Legislation) will be recovered. Therefore, the Company
recorded a $183 million after-tax extraordinary loss in the fourth quarter of
1999. 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 non-cash charge against earnings.
Pursuant to EITF 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
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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 $797 million of electric generation assets were
impaired as of June 30, 1999. Of these amounts, $745 million related to the
South Texas Project and $52 million related to two gas-fired generation plants.
The Legislation provides for recovery of this impairment through regulated cash
flows during the transition period and through non-bypassable charges to
transmission and distribution customers. As such, a regulatory asset has been
recorded for an amount equal to the impairment loss and is 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 and $329 million in 2000. The Company expects
to fully amortize this regulatory asset as it is recovered from regulated cash
flows 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 Legislation) 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 Legislation) will be collected through future non-bypassable
charges. Any over-mitigation of stranded costs may be refunded through future
non-bypassable 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. Because generally accepted
accounting principles require the Company to estimate fair market values on a
plant-by-plant basis in advance of the final reconciliation, the financial
impacts of the Legislation with respect to the final determination of stranded
costs in 2004 are subject to material changes. Factors affecting such change may
include estimation risk, uncertainty of future energy and commodity prices and
the economic lives of the plants. If events occur that make the recovery of all
or a portion of the regulatory assets associated with the generation plant
impairment loss and other assets created from discontinuance of SFAS No. 71
pursuant to the Legislation no longer probable, the Company will write off the
corresponding balance of these assets as a non-cash charge against earnings. One
of the results of discontinuing the application of SFAS No. 71 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. The Company believes it is probable that some parties will seek to
return these amounts to ratepayers and accordingly, the Company has recorded an
offsetting liability.
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. This
redirection was in accordance with the Company's Transition Plan. See Note 4(c)
for additional information regarding the Transition Plan. The Legislation
provides that depreciation expense for transmission and distribution related
assets may be redirected to generation assets during the base rate freeze period
from 1999 through 2001. For regulatory purposes, the Company has continued to
redirect transmission and distribution depreciation to generation assets.
Beginning June 30, 1999, redirected depreciation expense cannot 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, $99 million and $218 million in depreciation expense, respectively, has
been redirected from transmission and distribution for regulatory purposes and
has been established as an embedded regulatory asset included in transmission
and distribution related plant and equipment balances. As of December 31, 1999
and 2000, the cumulative amount of redirected depreciation for regulatory
purposes is $393 million and $611 million, respectively.
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The Company has reviewed its long-term purchase power contracts and fuel
contracts for potential loss in accordance with SFAS No. 5, "Accounting for
Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory
Pricing." Based on projections of future market prices for wholesale
electricity, the analysis indicated no loss recognition is appropriate at this
time.
Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71,
the accounting policies discussed below related to Electric Operations'
generation operations have been changed effective July 1, 1999. Allowance for
funds used during construction will no longer be accrued on generation related
construction projects. Instead, interest will be capitalized on these projects
in accordance with SFAS No. 34, "Capitalization of Interest Cost."
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 were 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.
General. As required by the Legislation, Reliant Energy submitted the
Business Separation Plan in 2000 to the Texas Utility Commission. The Business
Separation Plan was later amended to provide for the restructuring of the
Company's businesses into two separate and publicly traded companies in order to
separate its unregulated businesses from its regulated businesses. In December
2000, the plan was approved by the Texas Utility Commission. Reliant Resources
holds Reliant Energy's unregulated businesses, including the Wholesale Energy
segment, European Energy segment, communications business, eBusiness group, new
ventures group and retail electric business. As further described below, Reliant
Energy will undergo a restructuring of the Company's corporate organization to
achieve a holding company structure. This holding company will hold primarily
what are currently Reliant Energy's rate-regulated businesses. Reliant Resources
expects to conduct the Offering in 2001. After the Offering, Reliant Energy will
own approximately 80% of Reliant Resources common stock. Reliant Energy expects
the Offering to be followed by a distribution to Reliant Energy's or its
successor's shareholders of the remaining common stock of Reliant Resources
within 12 months of the Offering (the Distribution Date).
The Offering and the Distribution are subject to further corporate
approvals, market and other conditions, and government actions, including
receipt of a favorable Internal Revenue Service ruling that the Distribution
would be tax-free to Reliant Energy or its successor and its shareholders for
U.S. federal income tax purposes, as applicable. There can be no assurance that
the Offering and the Distribution will be completed as described or within the
time periods outlined above.
Restructuring of Regulated Entities. Under the Business Separation Plan,
Reliant Energy will restructure its regulated operations into a holding company
structure in which a new corporate entity (Regulated Holding Company) will be
formed as the parent with the Company's regulated businesses as subsidiaries.
This Regulated Holding Company is expected to own (a) the Company's electric
transmission and distribution operations, (b) its natural gas distribution
businesses, (c) initially, its regulated electric generating assets in Texas,
(d) its interstate pipelines, gas gathering and pipeline services operations,
and (e) its interests in energy companies in Latin America until disposition of
these investments (see Note 19). In these Notes, references to Reliant Energy in
connection with events occurring or the performance of agreements after the
restructuring generally refer to the Regulated Holding Company.
In connection with the formation of the new holding company for regulated
businesses, Reliant Energy expects to transfer the stock of all of its
subsidiaries to the new holding company and will transfer its regulated electric
generating assets in Texas to an indirect wholly owned partnership (Texas Genco)
until the stranded costs associated with those assets are valued in 2004. At
that time, Reliant Resources will have the right to
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exercise an option to acquire those assets, as further discussed below. As a
result of the stock and asset transfers described above, Reliant Energy will
become solely a transmission and distribution company, with its other businesses
becoming subsidiaries of the new holding company. Reliant Energy expects that
the regulated holding company will be required to assume all of Reliant Energy's
debt other than its first mortgage bonds, which would remain with Reliant
Energy. The indebtedness of some wholly owned financing subsidiaries is expected
to be refinanced by the regulated holding company by the end of 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
have been prepared and will be entered into by Reliant Energy and Reliant
Resources prior to the Offering.
Aspects of the restructuring of Reliant Energy's regulated businesses are
subject to the approval of Reliant Energy's shareholders and lenders and
approvals from the SEC under the Public Utility Holding Company Act and from the
United States Nuclear Regulatory Commission (NRC). There can be no assurance
that the restructuring of the Company's regulated businesses will be completed
as described above.
Agreements Related to Texas Generating Assets. Pursuant to the Business
Separation Plan, Reliant Energy expects to cause Texas Genco to either issue and
sell in an initial public offering or to distribute to its shareholders no more
than 20% of the common stock of Texas Genco by June 30, 2002. In connection with
the separation of its unregulated businesses from its regulated businesses,
Reliant Energy will grant Reliant Resources an option 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. 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 per share dividends
paid during the period there is a public ownership interest in Texas Genco and
Texas Genco's per share earnings during that period. If the disposition to the
public of common stock of Texas Genco is by means of a primary or secondary
public offering, the public offering may be of as little as 17% (rather than
19%) of Texas Genco's outstanding common stock, in which case Reliant Energy
will have the right to subsequently reduce its interest to a level not less than
80%. Reliant Resources will agree 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 Nuclear Regulatory Commission license transfer approval. The option will be
exercisable only if Reliant Energy or its successor distributes all of the
shares of Reliant Resources common stock it owns to its shareholders.
The Texas Genco option agreement will require Reliant Energy to take
commercially reasonable action as may be appropriate to cause Texas Genco to
have a capital structure appropriate, in the judgment of Reliant Energy's Board
of Directors, for the satisfactory marketing of Texas Genco common stock in an
initial public offering or to establish a satisfactory trading market for Texas
Genco common stock following a distribution of shares to Reliant Energy's
shareholders. It also will contain covenants relating to the operation of the
Texas Genco assets prior to the exercise or expiration of the option and require
that Reliant Energy maintain ownership of all equity of Texas Genco until
exercise or expiration of the Texas Genco option, subject to the initial public
offering or distribution obligation.
Reliant Resources will provide engineering and technical support services
and environmental, safety and industrial health services to support the
operations and maintenance of Texas Genco's facilities. Reliant
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Resources will also provide systems, technical, programming and consulting
support services and hardware maintenance (but excluding plant-specific
hardware) necessary to provide dispatch planning, dispatch and settlement and
communication with the independent system operator. The fees charged for these
services will be designed to allow Reliant Resources to recover its fully
allocated direct and indirect costs and reimbursement of out-of-pocket expenses.
Expenses associated with capital investment in systems and software that benefit
both the operation of Texas Genco's facilities and Reliant Resources' facilities
in other regions will be allocated on an installed megawatt basis. The term of
the technical services agreement will begin at the Distribution Date. The term
of this agreement will end on the first to occur of (a) the closing date of the
Reliant Resources' Texas Genco option, (b) Reliant Energy's sale of Texas Genco,
or all or substantially all of the assets of Texas Genco, if Reliant Resources
does not exercise the Texas Genco option, or (c) December 31, 2004, provided the
Texas Genco option is not exercised. Texas Genco may extend the term of this
agreement until December 31, 2005.
Pursuant to the Legislation, Texas Genco will be required to sell at
auction 15% of the output of its installed generating capacity beginning January
1, 2002. The first auction will be held on or before September 1, 2001 for power
delivered after 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 customers in the Reliant Energy HL&P traditional service area
is being served by retail electric providers other than subsidiaries of Reliant
Resources. Texas Genco plans to auction all of its remaining output during the
time period prior to Reliant Resources' exercise of the Texas Genco option.
Pursuant to the Business Separation Plan, Reliant Resources is entitled to
purchase, at prices established in these auctions, up to 50% of the remaining
capacity, energy and ancillary services auctioned by Texas Genco.
When Texas Genco is organized, it 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 will provide 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 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
ratepayers.
Retail Agreement between Reliant Energy and Reliant Resources. Under a
retail agreement, Reliant Resources will provide customer service call center
operations, credit and collections and revenue reporting services for Reliant
Energy's electric utility division and receiving and processing payments for the
accounts of Reliant Energy's electric utility division and two of Reliant
Energy's natural gas distribution divisions. Reliant Energy will provide the
office space and equipment for Reliant Resources to perform these services.
These services will terminate on January 1, 2002. The charges Reliant Energy
will pay Reliant Resources for these services are generally intended to allow
Reliant Resources to recover its fully allocated costs of providing the
services, plus out-of-pocket costs and expenses.
Service Agreements between Reliant Energy and Reliant Resources. Reliant
Resources plans to enter into agreements with Reliant Energy under which Reliant
Energy will provide Reliant Resources, on an interim basis, with various
corporate support services (including accounting, finance, investor relations,
planning, legal, communications, governmental and regulatory affairs and human
resources), information technology services and other previously shared services
such as corporate security, facilities management, accounts receivable, accounts
payable and payroll, office support services and purchasing and logistics.
These arrangements will continue after the Offering under a transition
services agreement providing for their continuation until December 31, 2004, or,
in the case of some corporate support services, until the
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Distribution Date. The charges Reliant Resources will pay Reliant Energy for
these services are generally intended to allow Reliant Energy to recover its
fully allocated costs of providing the services, plus out-of-pocket costs and
expenses. In each case, Reliant Resources will have the right to terminate
categories of services at an earlier date.
Pursuant to a lease agreement, Reliant Energy will lease Reliant Resources
office space in its headquarters building in Houston, Texas for an interim
period.
Other Agreements. In connection with the separation of Reliant Resources'
businesses from those of Reliant Energy, Reliant Resources will also enter into
other agreements providing, among other things, for mutual indemnities and
releases with respect to Reliant Resources' respective businesses and
operations, matters relating to corporate governance, matters relating to
responsibility for employee compensation and benefits, and allocation of tax
liabilities. In addition, Reliant Resources and Reliant Energy will enter into
various agreements relating to ongoing commercial arrangements, including among
other things the leasing of optical fiber and related maintenance activities,
rights to build fiber networks along existing rights of way, and the provision
of local exchange telecommunications and data services in the greater Houston
metropolitan area and long distance telecommunications services.
Reliant Energy will agree that $1.9 billion of intercompany indebtedness
owed by Reliant Resources and its subsidiaries prior to the closing of the
Offering will be converted into equity as a capital contribution to Reliant
Resources.
(c) Transition Plan.
In June 1998, the Texas Utility Commission issued an order in Docket No.
18465 approving the Company's Transition Plan filed by Reliant Energy HL&P in
December 1997. The Transition Plan included base rate credits to residential
customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose
monthly billing is 1,000 kva or less were entitled to receive base rate credits
of 2% in each of 1998 and 1999. The Company implemented the Transition Plan
effective January 1, 1998.
(d) Reliant Energy HL&P Filings.
As of December 31, 2000, Reliant Energy HL&P had recorded as a regulatory
asset under-recovered fuel cost of $558 million. In two separate filings in
2000, Reliant Energy HL&P filed and received approval to implement a fuel
surcharge 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.
On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and
address the Company's undercollected fuel costs of $389 million, which is the
accumulated amount since September 2000 through February 2001 plus estimates for
March and April, 2001. Reliant Energy HL&P is requesting to revise its fixed
fuel factor to be implemented with the May 2001 billing cycle and has proposed
to defer the collection of the $389 million until the 2004 stranded costs
true-up proceeding, discussed in Note 4(a) above.
o (5) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
The Company offers energy price risk management services primarily related
to natural gas, electric power and other energy related commodities. The Company
provides these services by utilizing a variety of derivative financial
instruments, including (a) fixed and variable-priced physical forward contracts,
(b) fixed and variable-priced swap agreements, (c) options traded in the
over-the-counter financial markets and (d) exchange-traded energy futures and
option contracts (Trading Derivatives). Fixed-price swap agreements require
payments to, or receipts of payments from, counterparties based on the
differential between a fixed and variable price for the commodity.
Variable-price swap agreements require payments to, or receipts of payments
from, counterparties based on the differential between industry pricing
publications or exchange quotations.
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The Company applies mark-to-market accounting for all of its energy
trading, marketing and price risk management operations. Accordingly, these
Trading Derivatives are recorded at fair value with realized and unrealized
gains (losses) recorded as a component of revenues. The recognized, unrealized
balances are included in price risk management assets/liabilities.
The notional quantities, maximum terms and the estimated fair value of
Trading Derivatives at December 31, 1999 and 2000 are presented below (volumes
in billions of British thermal units equivalent (Bbtue) and dollars in
millions):
VOLUME-FIXED VOLUME-FIXED MAXIMUM
PRICE PAYOR PRICE RECEIVER TERM (YEARS)
------------ -------------- ------------
1999
Natural gas.................................... 1,278,953 1,251,319 9
Electricity.................................... 242,868 239,452 10
Oil and other.................................. 285,251 286,521 3
2000
Natural gas.................................... 1,876,358 1,868,597 17
Electricity.................................... 526,556 523,942 6
Oil and other.................................. 52,820 42,380 2
FAIR VALUE AVERAGE FAIR VALUE(1)
--------------------- ---------------------
ASSETS LIABILITIES ASSETS LIABILITIES
------ ----------- ------ -----------
1999
Natural gas.................................. $ 581 $ 564 $ 550 $ 534
Electricity.................................. 122 91 96 74
Oil and other................................ 193 206 183 187
------ ------ ------ ------
$ 896 $ 861 $ 829 $ 795
====== ====== ====== ======
2000
Natural gas.................................. $4,059 $4,054 $2,058 $2,038
Electricity.................................. 1,115 1,087 601 561
Oil and other................................ 39 39 63 70
------ ------ ------ ------
$5,213 $5,180 $2,722 $2,669
====== ====== ====== ======
- ---------------
(1) Computed using the ending balance of each quarter.
In addition to the fixed-price notional volumes above, the Company also has
variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue and
3,004,336 Bbtue as of December 31, 1999 and 2000, respectively. Notional amounts
reflect the commodity volumes underlying the transactions but do not represent
the amounts exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not accurately measure the Company's exposure to market or
credit risks.
All of the fair values shown in the table above at December 31, 1999 and
2000, have been recognized in income. The Company estimated the fair value as of
December 31, 1999 and 2000, using quoted prices where available and other
valuation techniques when market data was not available, for example in illiquid
markets. For financial instruments for which quoted prices are not available,
the Company utilizes alternative pricing methodologies, including, but 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 prices and fair values are
subject to significant changes based on changing market conditions.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein 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
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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.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. The following table shows the composition of the total price
risk management assets of the Company as of December 31, 1999 and 2000.
DECEMBER 31, 1999 DECEMBER 31, 2000
------------------ -------------------
INVESTMENT INVESTMENT
GRADE(1) TOTAL GRADE(1) TOTAL
---------- ----- ---------- ------
(IN MILLIONS)
Energy marketers................................ $202 $230 $2,507 $2,709
Financial institutions.......................... 90 159 1,159 1,296
Gas and electric utilities...................... 220 221 511 586
Oil and gas producers........................... 31 31 500 599
Industrials..................................... 3 4 78 89
Others.......................................... 174 263 -- --
---- ---- ------ ------
Total................................. $720 908 $4,755 5,279
==== ======
Credit and other reserves....................... (12) (66)
---- ------
Energy price risk management assets(2).......... $896 $5,213
==== ======
- ---------------
(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) As of December 31, 2000, the Company had credit risk exposure to three
investment-grade counterparties that each represented greater than 5% of
price risk management assets. This information excludes some offsetting
contracts that either require or permit net settlement with non-trading
transactions not included in price risk management assets. The Company's
resulting net credit risk exposure to these three counterparties is below 5%
of price risk management assets.
(b) Non-Trading Activities.
To reduce the risk from market fluctuations in the revenues derived from
the sale of electric power and natural gas and related transportation, the
Company enters into futures transactions, forward contracts, swaps and options
(Energy Derivatives) in order to hedge some expected purchases of electric power
and natural gas and sales of electric power and natural gas (a portion of which
are firm commitments at the inception of the hedge). Energy Derivatives are also
utilized to fix the price of compressor fuel or other future operational gas
requirements and to protect natural gas distribution earnings against
unseasonably warm weather during peak gas heating months, although usage to date
for this purpose has not been material. The Company applies hedge accounting for
its derivative financial instruments utilized in non-trading activities.
Unrealized changes in the market value of Energy Derivatives utilized as hedges
are not generally recognized in the Company's Statements of Consolidated
Operations until the underlying hedged transaction occurs. Once it becomes
probable that an anticipated transaction will not occur, the Company recognizes
deferred gains and losses. In general, the financial impact of transactions
involving these Energy Derivatives is included in the Company's Statements of
Consolidated Operations under the captions (a) fuel expenses, in the case of
natural gas transactions, (b) purchased power, in the case of electric power
purchase transactions, and (c) revenues, in the case of electric power sales
transactions. Cash flows resulting from these transactions in Energy Derivatives
are included in the Company's Statements of Consolidated Cash Flows in the same
category as the item being hedged.
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In connection with the Company's acquisition of UNA in 1999, the Company
entered into call option agreements with several banks to hedge the impact of
foreign exchange movements on the Dutch guilder. These call options provided the
right, but not the obligation, to purchase NLG 695 million from specific banks
at specific strike prices. The total premium paid, classified as other expense
on the Company's Statement of Consolidated Operations, for all of the options
that were to expire on October 26, 1999, was $8 million. On October 12, 1999,
the Company sold the remaining value in the call options for $0.6 million. The
proceeds were reflected in the Company's results of operations as a reduction of
other expense.
As of December 31, 1999 and 2000, the Company had outstanding foreign
currency swaps for 258 million and Euros 671 million, respectively
(approximately $228 million and $632 million), terminating in September 2000 and
January 2001, respectively. The Company also issued Euro-denominated debt,
maturing in March and June 2001. The foreign currency swaps and Euro-denominated
debt hedge the Company's net investment in UNA. In January 2001, the Company
entered into foreign currency swaps for Euros 671 million (approximately $633
million) to replace the foreign currency swaps that expired in January 2001.
These foreign currency swaps terminate in January 2002. In January and March
2001, the Company entered into foreign currency forward contracts for Euros 159
million (approximately $150 million) to adjust the hedge of its net investment
in UNA. These forward contracts expire in January 2002. The Company records
changes in the value of the hedging instruments and debt as foreign currency
translation adjustments as a component of stockholders' equity and 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 net investment in UNA. These amounts generally offset amounts
recorded in stockholders' equity as adjustments resulting from translation of
the hedged investment into U.S. dollars. As of December 31, 1999 and 2000, the
net carrying value of the currency swaps was a $6 million receivable and $62
million obligation, respectively, and was recorded in other current assets and
other current liabilities in the Company's Consolidated Balance Sheets.
During 2000, European Energy entered into financial instruments to purchase
approximately $120 million to hedge future fuel purchases payable in U.S.
dollars. As of December 31, 2000, the fair value of these financial instruments
was a $6 million liability. Unrealized changes in the market value of these
financial instruments are not recognized in the Company's Statements of
Consolidated Operations until the underlying hedged transaction occurs.
For transactions involving either Energy Derivatives or foreign currency
derivatives, hedge accounting is applied only if the derivative reduces the risk
of the underlying hedged item and is designated as a hedge at its inception.
Additionally, the derivatives must be expected to result in financial impacts
that are inversely correlated to those of the item(s) to be 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% for hedge designation. If and when correlation ceases to exist at
an acceptable level, hedge accounting ceases and mark-to-market accounting is
applied.
At December 31, 1999, the Company was a fixed-price payor and a fixed-price
receiver in Energy Derivatives covering 33,108 Bbtu and 5,481 Bbtu of natural
gas, respectively. At December 31, 2000, the Company was a fixed-price payor and
a fixed-price receiver in Energy Derivatives covering 198,001 Bbtu and 22,874
Bbtu of natural gas, respectively, and 486 Bbtu and zero Bbtu of oil,
respectively. In addition to the fixed-price notional volumes above, the Company
also has variable-priced agreements totaling 44,958 Bbtu and 174,900 Bbtu of
natural gas at December 31, 1999 and 2000, respectively. The weighted average
maturity of these instruments is less than two years.
The notional amount is intended to be indicative of the Company's level of
activity in these derivatives. However, the amounts at risk are significantly
smaller because, in view of the price movement correlation required for hedge
accounting, changes in the market value of these derivatives generally are
offset by changes in the value associated with the underlying physical
transactions or in other derivatives. When Energy Derivatives are closed out in
advance of the underlying commitment or anticipated transaction, however, the
market value changes may not offset due to the fact that price movement
correlation ceases to exist when the
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positions are closed, as further discussed above. Under these circumstances,
gains (losses) are deferred and recognized as a component of income when the
underlying hedged item is recognized in income.
The average maturity discussed above and the fair value discussed in Note
15 are not necessarily 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.
(c) Trading and Non-trading -- General Policy.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management 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. In order to minimize this risk, the Company enters into
these contracts primarily with counterparties having a minimum investment grade
index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3,
respectively. For long-term arrangements, the Company periodically reviews the
financial condition of these firms 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. 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 credit risk
related to the California wholesale electricity market, see Note 14(h).
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.
The Company has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading, marketing, power
origination and risk management activities. The committee's duties are to
establish 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 ensure compliance with the
Company's risk management policies and procedures and trading limits established
by the Company's Board of Directors.
o (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 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 and $41 million in
1998. 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.
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(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 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 TW Common, or other securities distributed
with respect to TW Common (one share of TW Common and such other securities, if
any, are referred to as reference shares). Each ZENS has an original principal
amount of $58.25 (the closing market price of the TW Common on September 15,
1999) 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, 2000, no interest payments on the ZENS had been deferred.
On January 11, 2001, TW and America Online, Inc. combined to form AOL Time
Warner Inc. (AOL TW). As a result of the combination each share of TW Common was
converted into 1.5 shares of AOL TW Common Stock (AOL TW Common) and the Company
now holds 25.8 million shares of AOL TW Common. As a result of the combination,
the reference shares attributable to one ZENS is 1.5 shares of AOL TW Common.
The Company used $537 million of the net proceeds from the offering of the
ZENS to purchase 9.2 million shares of TW Common, which are classified as
trading securities under SFAS No. 115. Unrealized gains and losses resulting
from changes in the market value of the TW Common are recorded in the Company's
Statements of Consolidated Operations.
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. As of December
31, 1999 and 2000, the market value of TW Common was $72.31 and $52.24,
respectively. Therefore, during 2000, the Company recorded a pre-tax net
unrealized loss on its investment in TW Common and its obligation on its indexed
debt securities of $103 million.
Prior to the purchase of additional shares of TW Common on September 21,
1999, the Company owned approximately 8 million shares of TW Common that were in
excess of the 38 million shares needed to economically hedge its ACES
obligation. For the period from July 6, 1999 to the ZENS issuance date, losses
(due to the decline in the market value of the TW Common during such period) on
these 8 million shares were $122 million ($79 million after-tax). The 8 million
shares of TW Common combined with the additional 9.2 million shares purchased
are expected to be held to facilitate the Company's ability to meet its
obligation under the ZENS.
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The following table sets forth summarized financial information regarding
the Company's investment in TW securities and the Company's ACES and ZENS
obligations.
TW INVESTMENT ACES ZENS
------------- ------- ------
(IN MILLIONS)
Balance at December 31, 1997......................... $ 990 $ 1,174
Loss on indexed debt securities...................... -- 1,176
------- -------
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
======= ======= ======
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS
obligation is 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 is valued at fair value and determines 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 is 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. The transition adjustment gain will be 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
Operations. Changes in the fair value of the AOL TW Common held by the Company
should substantially offset changes in the fair values of the derivative
component of the ZENS.
o (14) COMMITMENTS AND CONTINGENCIES
(a) Capital and Environmental Commitments.
The Company has various commitments for capital and environmental
expenditures. The Wholesale Energy segment has entered into commitments
associated with various non-rate regulated electric generating projects,
including commitments for the purchase of combustion turbines aggregating $436
million. In addition, the Wholesale Energy segment has options to purchase
additional generating equipment for a total estimated cost of $544 million for
future generating projects.
The Company anticipates investing up to $711 million in capital and other
special project expenditures between 2001 and 2005 for environmental compliance.
The Company anticipates expenditures to be as follows (in millions):
2001........................................................ $217
2002........................................................ 259
2003........................................................ 80
2004........................................................ 76
2005........................................................ 79
----
Total............................................. $711
====
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(b) Fuel and Purchased Power.
Reliant Energy HL&P is a party to several long-term coal, lignite and
natural gas contracts, which have various quantity requirements and durations.
Minimum payment obligations for coal and transportation agreements that extend
through 2011 are approximately $280 million in 2001, $281 million in 2002 and
$274 million in 2003. Purchase commitments related to lignite mining and lease
agreements, natural gas purchases and storage contracts, and purchased power are
not material to the operations of the Company. Currently, Reliant Energy HL&P is
allowed recovery of these costs through base rates for electric service. As of
December 31, 2000, some of these contracts are above market. The Company
anticipates that stranded costs associated with these obligations will be
recoverable through the stranded costs recovery mechanisms contained in the
Legislation. For information regarding the Legislation, see Note 4(a).
REMA is a party to several long-term fuel supply contracts which have
various quantity requirements and durations. Minimum payment obligations under
these agreements that extend through 2004 are as follows as of December 31, 2000
(in millions):
2001........................................................ $ 85
2002........................................................ 66
2003........................................................ 29
2004........................................................ 14
----
Total............................................. $194
====
The Company'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 the Company's results of operations or cash
flows.
(c) Lease Commitments.
In August 2000, the Company entered into separate sale/leaseback
transactions with each of three owner-lessors for the Company's 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
some 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, guarantees the lease obligations.
The Company will make lease payments through 2029. The lease terms expire in
2034.
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2000, which primarily relate to the REMA leases mentioned above. Other
non-cancelable long-term operating leases principally consist of rental
agreements for building space, data processing equipment and vehicles, including
major work equipment.
REMA
SALE-LEASE
OBLIGATION OTHER TOTAL
---------- ----- ------
(IN MILLIONS)
2001....................................................... $ 259 $ 16 $ 275
2002....................................................... 137 10 147
2003....................................................... 77 8 85
2004....................................................... 84 6 90
2005....................................................... 75 6 81
2006 and beyond............................................ 1,188 36 1,224
------ ---- ------
Total............................................ $1,820 $ 82 $1,902
====== ==== ======
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Total lease expense for all operating leases was $10 million, $13 million
and $46 million during 1998, 1999 and 2000, respectively.
(d) Cross Border Leases.
During the period from 1994 through 1997, under cross border lease
transactions, UNA 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, 2000, of 1 to 24 years. UNA 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 $1.7 billion
remained outstanding as of December 31, 2000. These transactions involve UNA
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 UNA of the
transactions were recorded as a deferred gain and are currently being amortized
to income over the lease terms. At December 31, 1999 and 2000, the unamortized
deferred gain on these transactions totaled $87 million and $77 million,
respectively. The power plants, related equipment and turbines remain on the
financial statements of UNA and continue to be depreciated.
UNA is required to maintain minimum insurance coverages, perform minimum
annual maintenance and, in specified situations, post letters of credit. UNA's
shareholder is subject to some restrictions with respect to the liquidation of
UNA's shares. In the case of early termination of these contracts, UNA would be
contingently liable for some payments to the sublessors, which at December 31,
2000, are estimated to be $274 million. Starting in March 2000, UNA 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 $274 million as of December 31, 2000. Commitments for
these letters of credit have been obtained as of December 31, 2000.
(e) Naming Rights to Houston Sports Complex.
In October 2000, the Company 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 the Company with
significant sponsorship rights. The aggregate cost of the naming rights will be
approximately $300 million. During the fourth quarter of 2000, the Company
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 Company's Statement of Consolidated Operations in 2000. Starting in 2002,
when the new stadium is operational, the Company will pay $10 million each year
through 2032 for annual advertising under this agreement.
(f) 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, 1999 and 2000, 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 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.
(g) 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
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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 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 opinions over the past decade. The Company estimates the range of
possible outcomes for the plaintiffs to be between zero and $17 million
inclusive of interest and attorneys' fees.
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.
California Wholesale Market. Reliant Energy and Reliant Energy Services,
Inc. 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. RERC Corp. has also been
named as a defendant on one of the lawsuits. Pursuant to the terms of the master
separation agreement between Reliant Energy and Reliant Resources (see Note
4(b)), Reliant Resources will agree to indemnify RERC Corp. for any damages
arising under this lawsuit, and will agree to indemnify Reliant Energy for
damages arising under any of these lawsuits, and may elect to defend these
lawsuits at Reliant Resources' 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. 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
during all or portions of 2000, costs of suit and attorneys' fees. In one of the
cases the plaintiffs allege aggregate damages of over $4 billion. Defendants
have filed petitions to remove the cases to federal court. Furthermore,
defendants have filed a motion with the Panel on Multidistrict Litigation
seeking transfer and consolidation of all the cases. These lawsuits have only
recently been filed. Therefore, the ultimate outcome of the lawsuits cannot be
predicted with any degree of certainty at this time. However, the Company does
not believe, based on its analysis to date of the claims asserted in these
lawsuits and the underlying facts, that resolution of these lawsuits will have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
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ENVIRONMENTAL MATTERS.
Manufactured Gas Plant Sites. RERC Corp. and its subsidiaries (RERC) and
its predecessors operated a manufactured gas plant (MGP) adjacent to the
Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW)
until 1960. 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, 1999 and 2000, RERC had accrued $19 million and $17
million, respectively, for remediation of the Minnesota sites. At December 31,
2000, the estimated range of possible remediation costs was $8 million to $36
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, if any, and the remediation methods used.
Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded
accruals of $1 million and $2 million, respectively (with a maximum estimated
exposure of approximately $13 million and $17 million at December 31, 1999 and
2000, respectively), for other environmental matters in Minnesota for which
remediation may be required.
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 potentially responsible party (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.
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 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, REMA has liabilities associated with six ash disposal site
closures and six 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. The Company expects approximately $13
million will be paid over the next five years.
UNA Asbestos Abatement and Soil Remediation. Prior to the Company's
acquisition of UNA (see Note 3(b)), UNA 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 UNA's properties. UNA 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
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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, the estimated undiscounted liability for this asbestos abatement and soil
remediation was $24 million.
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.
In addition, the Company has been named as a defendant in litigation related to
such 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.
(h) California Wholesale Market Uncertainty.
During the summer and fall of 2000, 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, decreases in net
electric imports, structural market flaws including over-reliance on the
electric spot market, and limitations on supply as a result of maintenance and
other outages. Although wholesale prices increased, California's deregulation
legislation kept retail rates frozen below 1996 levels. This caused two of
California's public utilities, which are the Company's customers based on its
deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of
uncollected wholesale power costs and to ultimately default in January and
February 2001 on payments owed for wholesale power purchased through the Cal PX
and from the Cal ISO.
As of December 31, 2000, the Company was owed $101 million by the Cal PX
and $181 million by the Cal ISO. In the fourth quarter of 2000, the Company
recorded a pre-tax provision of $39 million against receivable balances related
to energy sales in the California market. From January 1, 2001 through February
28, 2001, the Company has collected $105 million of these receivable balances.
As of March 1, 2001, the Company was owed a total of $358 million by the Cal
ISO, the Cal PX, the California Department of Water Resources (CDWR) and
California Energy Resource Scheduling, for energy sales in the California
wholesale market from the fourth quarter of 2000 through February 28, 2001.
Management will continue to assess the collectibility of these receivables based
on further developments affecting the California electricity market and the
market participants described herein. Additional provisions to the allowance may
be warranted in the future.
In response to the filing of a number of complaints challenging the level
of wholesale prices, the FERC initiated a staff investigation and issued an
order on December 15, 2000 implementing a series of wholesale market reforms,
including an interim price review procedure for prices above a $150/MWh
"breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not
prohibit sales above the "breakpoint," but the seller is subject to weekly
reporting and monitoring requirements. For each reported transaction, potential
refund liability extends for a period of 60 days following the date any such
transaction is reported to the FERC. On March 9, 2001, the FERC issued a further
order establishing a proxy market
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clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC
issued a further order adjusting the proxy market clearing price to $430/MWh for
February 2001. New market monitoring and mitigation measures to replace the
$150/MWh breakpoint and reporting obligation are being developed by the FERC to
take effect on May 1, 2001.
In the FERC's March 9 and March 16 orders, the FERC outlined criteria for
determining amounts subject to possible refund based on the proxy market
clearing price for January and February 2001 and indicated that approximately
$12 million of the $125 million charged by the Company in January 2001 in
California to the Cal ISO and the Cal PX and approximately $7 million of the $47
million charged by the Company in February 2001 in California to the Cal ISO and
the Cal PX were subject to possible refunds. In the March 9 and March 16 orders,
the FERC set forth procedures for challenging possible refund obligations.
Because the Company believes that there is cost or other justification for
prices charged above the proxy market clearing prices established in the March 9
and March 16 orders, the Company intends to pursue such a challenge with respect
to the Company's potential refund amounts identified in such orders. Any refunds
the Company may ultimately be obligated to pay are to be credited against unpaid
amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The
December 15 order established that a refund condition would be in place for the
period beginning October 2, 2000 through December 31, 2002. The December 15
order also eliminated the requirement that California's public utilities sell
all of their generation into and purchase all of their power from the Cal PX and
directed that the Cal PX wholesale tariffs be terminated effective April 2001.
The Cal PX has since suspended its day-ahead and day-of markets and filed for
bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on
a number of issues related to the December 15 order and such motions are still
pending before the FERC.
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 Public
Utilities Commission, the California Electricity Oversight Board, the California
Bureau of State Audits and the California Office of the Attorney General all
have separate ongoing investigations into the high prices and their causes. None
of these investigations have been completed and no findings have been made in
connection with any of them.
Despite the market restructuring ordered under the December 15 order, the
California public utilities have continued to accrue unrecovered wholesale
costs. As a result, the credit ratings of two of these public utilities were
severely downgraded to below investment grade in January 2001. As their credit
lines became unavailable, the two utilities defaulted on payments due to the Cal
PX and the Cal ISO, which operate financially as pass-through entities,
coordinating payments from buyers and sellers of electricity. As a result, the
Cal PX and Cal ISO were not able to pay final invoices to market participants
totaling over $1 billion.
The default of two of California's public utilities on amounts owed the Cal
PX and the Cal ISO for purchased power has further exacerbated the current
crisis in the California wholesale markets and resulted in substantial
uncollected receivables owed to the Company by the Cal ISO and the Cal PX. The
Cal PX's efforts to recover the available collateral of the utilities, in the
form of block forward contracts, have been frustrated by the emergency acts of
California's Governor, who seized control of the contracts upon the expiration
of temporary restraining orders prohibiting such action. Although obligated to
pay reasonable value for the contracts, the state of California has not yet made
any payment for the contracts. Various actions have been filed challenging the
Governor's ability to seize these contracts.
Upon the default of the two utilities of amounts due to the Cal PX, the Cal
PX issued "charge-backs" allocating the utilities' defaults to the other market
participants. Proceedings were brought both in federal court and at the FERC
seeking a suspension of the charge-backs and challenging the reasonableness of
the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction
suspending any of its charge-back activities in order to allow the FERC to
address the charge-back issues. Amounts owed to the Company were debited in
invoices by the Cal PX for charge-backs in the amount of $29 million and, on
February 14, 2001, the Company filed its own lawsuit against the Cal PX in the
United States District Court for the Central District of California, seeking a
recovery of those amounts and a stay of any further charge-backs by the Cal
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PX. The filing of bankruptcy by the Cal PX will automatically stay for some
period the various court and administrative cases against the Cal PX.
The two defaulting utilities have both filed lawsuits challenging the
refusal of state regulators to allow wholesale power costs to be passed through
to retail customers under the "filed rate doctrine". The filed rate doctrine
provides that wholesale power costs approved by the FERC are entitled to be
recovered through rates. Additionally, to address the failing financial
condition of the two defaulting utilities and the utilities' potential
bankruptcy, the California Legislature passed emergency legislation, effective
January 18, 2001 and February 2, 2001, appropriating funds to be used by the
CDWR for the purchase of wholesale electricity on behalf of the utilities and
authorizing the sale of bonds to fund future purchases under long-term power
contracts with wholesale generators. The CDWR began the process of soliciting
bids from generators for long-term contracts and continued the purchasing of
short-term power contracts. No bonds have yet been issued by the CDWR to support
long-term power purchases or to provide credit support for short-term purchases.
As noted above two of California's public utilities have defaulted in their
payment obligations to the Cal PX and the Cal ISO as a result of the refusal of
state regulators to allow them to recover their wholesale power costs. This
refusal by state regulators has also caused the utilities to default on numerous
other financial obligations, which could result in either the voluntary or
involuntary bankruptcy of the utilities. While a bankruptcy filing would result
in further post-petition purchases of wholesale electricity being considered
administrative expenses of the debtor, a substantial delay could be experienced
in the payment of pre-petition receivables pending the confirmation of a
reorganization plan. The California Legislature is currently considering
legislation under which a state entity would be formed to purchase and operate a
substantial share of the transmission lines in California in an effort to
provide cash to the utilities and thereby avoid potential bankruptcy filings by
the utilities. A number of the creditors for the two California public utilities
have indicated, however, that unless California moves quickly with such a plan,
an involuntary bankruptcy filing may be made by one or more of such creditors.
Because California's power reserves remain at low levels, in part as a
result of the lack of creditworthy buyers of power given the defaults of the
California utilities, the Cal ISO has relied on emergency dispatch orders
requiring generators to provide at the Cal ISO's direction all power not already
under contract. The power supplied to the Cal ISO has been used to meet the
needs of the customers of the utilities, even though two of those utilities do
not have the credit required to receive such power and may be unable to pay for
it. The Company has contested the obligation to provide power under these
circumstances. The Cal ISO sought a temporary restraining order compelling the
Company to continue to comply with the emergency dispatch orders despite the
utilities' defaults. Although the payment issue is still disputed, on February
21, 2001, the Company and the CDWR entered into a contract expiring March 23,
2001 for the purchase of all of the Company's available capacity not already
under contract and the litigation has been temporarily stayed. The CDWR is
current in its payments under this contract, but the Company is still owed $108
million for power provided in compliance with the emergency dispatch orders for
the six weeks prior to the agreement. Depending on the outcome of the court
proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power
deliveries to the Cal ISO, the Company may be forced to continue selling power
without the guarantee of payment.
Additionally, the Company is seeking a prompt FERC determination that the
Cal ISO is not complying with the credit provisions of its tariff and a related
order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make
purchases in the real time market unless a creditworthy purchaser is responsible
for such purchases.
(i) Indemnification of Stranded Costs.
The stranded costs in the Dutch electricity market are considered to be the
liabilities, uneconomical contractual commitments, and other costs associated
with obligations entered into by the coordinating body for the Dutch electricity
generating sector, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP),
plus some district heating contracts with some municipalities in Holland. As of
December 29, 2000, SEP changed its name to BV Nederlands Elektriciteit
Administratiekantoor.
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SEP was incorporated as the coordinating body for four of the large-scale
Dutch electricity generation companies, including UNA, which currently has an
equity interest in SEP of 25%. Among other things, SEP prior to 2001 owned and
managed the dispatch for the national transmission grid, coordinated the fuel
supply, managed the import and the export of electricity, and settled production
costs for the electricity generation companies.
Under the Cooperation Agreement (OvS Agreement), UNA and the other Dutch
generators agreed to sell their generating output through SEP. Over the years,
SEP incurred stranded costs as a result of a perceived need to cover anticipated
shortages in energy production supply. SEP stranded costs consist primarily of
investments in alternative energy sources and fuel and power purchase contracts
currently estimated to be uneconomical.
In December 2000, the Dutch parliament adopted legislation, The Electricity
Production Sector Transitional Arrangements Act (Transition Act), allocating to
the Dutch generation sector, including UNA, financial responsibility for various
stranded costs contracts and other liabilities of SEP. The Transition Act also
authorizes the government to purchase from SEP at least a majority of the shares
in the Dutch national transmission grid company. The legislation became
effective in all material respects on January 1, 2001.
The Transition Act allocates financial responsibility to the individual
Dutch generators based on their average share in the costs and revenues under
the OvS Agreement during the past ten years. UNA's allocated share of these
costs has been set at 22.5%. In particular, the Transition Act allocates to the
four Dutch generation companies, including UNA, financial responsibility for
SEP's obligations to purchase electricity and gas under an import gas supply
contract and three electricity import contracts. The gas import contract expires
in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per
year. The three electricity contracts have the following capacities and terms:
(a) 300 MW through 2005, (b) 600 MW through 2005 and (c) 600 MW through 2002 and
750 MW through 2009. The generators have the option of assuming their pro rata
interests in the contracts or, subject to the assignment terms of the contracts,
selling their interests to third parties.
The Transition Act provides that, subject to the approval of the European
Commission, the Dutch government will make financial compensations to the Dutch
generation sector for the out of market costs associated with two stranded cost
items: an experimental coal facility and district heating contracts.
The four Dutch generation companies and SEP are in discussions with the
Dutch Ministry of Economic Affairs regarding the implementation of the
Transition Act. The parties have reached an agreement in principle with the
Dutch Ministry of Economic Affairs regarding the compensation to be paid to SEP
for the national transmission grid company. The proposed compensation amount is
NLG 2.55 billion (approximately $1.1 billion based on an exchange rate of 2.34
NLG per U.S. dollar as of December 31, 2000). Although the Transition Act
clarifies many issues regarding the anticipated resolution of the stranded costs
debate in the Netherlands, there remain considerable uncertainties regarding the
exact manner in which the Transition Act will be implemented and the potential
for third parties to challenge the Transition Act on legal and constitutional
grounds.
In connection with the acquisition of UNA, the selling shareholders of UNA
agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG
1.4 billion (approximately $599 million based on an exchange rate of 2.34 NLG
per U.S. dollar as of December 31, 2000), which may be increased in some
circumstances at the option of the Company up to NLG 1.9 billion (approximately
$812 million). Of the total consideration paid by the Company for the shares of
UNA, NLG 900 million (approximately $385 million) has been placed by the selling
shareholders in an escrow account under the direction of the Dutch Ministry of
Economic Affairs to secure the indemnity obligations. Although the Company's
management believes that the indemnity provision will be sufficient to fully
satisfy UNA's ultimate share of any stranded costs obligation, this judgment is
based on numerous assumptions regarding the ultimate outcome and timing of the
resolution of the stranded cost issue, the former shareholders' timely
performance of their obligations under the indemnity arrangement, and the amount
of stranded costs which at present is not determinable.
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(j) 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 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. It is anticipated that
the cumulative obligation will be met in the first quarter of 2001. In 1998,
1999 and 2000, savings generated for CPS' account were $14 million, $14 million
and $60 million, respectively. Through December 31, 2000, cumulative savings
generated for CPS' account were $124 million.
(k) 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, 2000. 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.
(l) Nuclear Decommissioning.
The Company contributes $14.8 million per year to a trust established to
fund its share of the decommissioning costs for the South Texas Project. 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 and projected 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
Legislation, 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 non-bypassable 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).
o (20) SUBSEQUENT EVENTS
(a) Credit Facilities.
Between December 2000 and March 2001, Reliant Resources entered into eleven
bilateral credit facilities with financial institutions, which provide for an
aggregate of $1.6 billion in committed credit. The facilities became effective
subsequent to December 31, 2000 and expire on October 2, 2001. Concurrent with
the effectiveness of these facilities, $500 million of the facilities of a
financing subsidiary were canceled. Interest rates on the borrowings are based
on LIBOR plus a margin, a base rate or a rate determined through a bidding
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process. These facilities contain various business and financial covenants
requiring Reliant Resources to, among other things, maintain a ratio of net debt
to the sum of net debt, subordinated affiliate debt and shareholders' 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 credit facilities are subject to commitment and
usage fees that are calculated based on the amount of the facility and/or the
amounts outstanding under the facilities, respectively.
(b) 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.
(c) Florida Tolling Arrangement.
In the first quarter 2001, the Company entered into tolling arrangements
with a third party to purchase the right to utilize and dispatch electric
generating capacity of approximately 1,100 MW. This electricity is expected to
be generated by two gas-fired, simple-cycle peaking plants, with fuel oil
backup, to be constructed by the tolling partner in Florida, which are
anticipated to be completed by the summer of 2002, at which time the Company
will commence tolling payments.
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