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EXHIBIT 99.RERC
RELIANT ENERGY RESOURCES CORP.
ITEMS INCORPORATED BY REFERENCE
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K
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.
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
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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.
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
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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."
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
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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.
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.
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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.
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
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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 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
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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.
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
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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. 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.
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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 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.
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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 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.
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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.
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.
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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.
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.
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ITEMS INCORPORATED BY REFERENCE FROM THE
RELIANT ENERGY RESOURCE CORP. FORM 10-K
o ITEM 3. LEGAL PROCEEDINGS
(b) RERC CORP.
For a description of certain legal and regulatory proceedings affecting
RERC, see Notes 9(c) and 9(d) to RERC's consolidated financial statements, which
notes are incorporated herein by reference.
o ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RERC
AND ITS CONSOLIDATED SUBSIDIARIES
The following narrative and analysis should be read in combination with the
consolidated financial statements and notes of Reliant Energy Resources Corp.
(RERC Corp.) and its subsidiaries (collectively, RERC) contained in Item 8 of
the Form 10-K of RERC Corp.
RELIANT ENERGY RESOURCES CORP.
Because RERC Corp. is a wholly owned subsidiary of Reliant Energy,
Incorporated (Reliant Energy), RERC's determination of reportable segments
considers the strategic operating units under which Reliant Energy manages
sales, allocates resources and assesses performance of various products and
services to wholesale or retail customers in differing regulatory environments.
Reliant Energy has identified the following reportable segments: Electric
Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy,
European Energy, and Other Operations. Of these segments, the following
operations have historically been conducted by RERC:
- Natural Gas Distribution,
- Pipelines and Gathering,
- Wholesale Energy (which includes wholesale energy trading, marketing,
power origination and risk management services in North America but
excludes the operations of Reliant Energy Power Generation, Inc., an
indirect wholly owned subsidiary of Reliant Energy),
- European Energy (which includes the energy trading and marketing
operations initiated in the fourth quarter of 1999 in the Netherlands and
other countries in Europe but excludes N.V. UNA, a Dutch power company),
and
- Certain Other Operations.
On July 27, 2000, Reliant Energy announced its intention to divide into two
publicly traded companies in order to separate its unregulated businesses from
its regulated businesses. In August 2000, Reliant Energy formed Reliant
Resources, Inc. (Reliant Resources) to own and operate a substantial portion of
Reliant Energy's unregulated operations and to offer no more than 20% of Reliant
Resources' common stock in an initial public offering (Offering). 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 twelve months after the Offering.
On December 31, 2000, RERC Corp. transferred all of the outstanding capital
stock of Reliant Energy Services International, Inc. (RESI), Arkla Finance
Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc.
(RE Europe Trading), all of which were wholly owned subsidiaries of RERC Corp.,
to Reliant Resources (collectively, Stock Transfer). Both RERC Corp. and Reliant
Resources are wholly owned subsidiaries of Reliant Energy. As a result of the
Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly
owned subsidiary of Reliant Resources.
Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources
merged with and into Reliant Energy Services, Inc. (Reliant Energy Services), a
wholly owned subsidiary of RERC Corp., with
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Reliant Energy Services as the surviving corporation (Merger). As a result of
the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant
Resources. As consideration for the Stock Transfer and the Merger, Reliant
Resources paid $94 million to RERC Corp.
Reliant Energy Services, together with RESI and RE Europe Trading, conduct
the Wholesale Energy segment's trading, marketing, power origination and risk
management business and operations of Reliant Energy. Arkla Finance is a company
that holds an investment in marketable equity securities.
RERC Corp. has guaranteed or indemnified the performance of a portion of
the obligations of Reliant Energy's trading, marketing, power origination and
risk management businesses. Some of these guarantees and indemnities are for
fixed amounts, others have a fixed maximum amount and others do not specify a
maximum amount. Pursuant to the master separation agreement, Reliant Resources
will agree to indemnify RERC Corp. for any amounts RERC Corp. pays under these
guarantees and indemnities.
The Stock Transfer and the Merger are part of Reliant Energy's previously
announced restructuring. RERC is reporting the results of RE Europe Trading as
discontinued operations for all periods presented in the consolidated financial
statements in accordance with Accounting Principles Board Opinion No. 30. For
additional information regarding the operating results of the entities
transferred to Reliant Resources, please read Note 13 to RERC's consolidated
financial statements.
RERC Corp. meets the conditions specified in General Instruction I (1)(a)
and (b) to Form 10-K and is thereby permitted to use the reduced disclosure
format for wholly owned subsidiaries of reporting companies specified therein.
Accordingly, RERC Corp. has omitted from this Combined Form 10-K the information
called for by Item 4 (submission of matters to a vote of security holders), Item
10 (directors and executive officers), Item 11 (executive compensation), Item 12
(security ownership of certain beneficial owners and management) and Item 13
(certain relationships and related party transactions) of Form 10-K. In lieu of
the information called for by Item 6 (selected financial data) and Item 7
(management's discussion and analysis of financial condition and results of
operations) of Form 10-K, RERC Corp. has included the following Management's
Narrative Analysis of the Results of Operations to explain material changes in
the amount of revenue and expense items of RERC between 1998, 1999 and 2000.
Reference is hereby made to Item 1 (Business), Item 2 (Properties), Item 3
(Legal Proceedings), Item 5 (Market for Reliant Energy's and RERC Corp's Common
Equity and Related Stockholder Matters), Item 7A (Quantitative and Qualitative
Disclosures about Market Risk) and Item 9 (Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure) of this Combined Form 10-K
for additional information regarding RERC required by the reduced disclosure
format of General Instruction I to Form 10-K.
CONSOLIDATED RESULTS OF OPERATIONS
RERC's results of operations are affected by seasonal fluctuations in the
demand for natural gas and price movements of energy commodities. RERC's results
of operations are also affected by, among other things, the actions of various
federal and state governmental authorities having jurisdiction over rates
charged by RERC, competition in RERC's various business operations, debt service
costs and income tax expense. For a discussion of some other factors that may
affect RERC's future earnings please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Our Future Earnings -- Business Separation and Restructuring," "-- Competitive
and Other Factors Affecting RERC Operations" and "-- Environmental Expenditures"
in Item 7 of Reliant Energy's 2000 Form 10-K.
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The following table sets forth selected financial and operating data for
the years ended December 31, 1998, 1999 and 2000, followed by a discussion of
significant variances in period-to-period results:
SELECTED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1999 2000
------- -------- --------
(IN MILLIONS)
Operating Revenues.................................... $ 6,758 $ 10,543 $ 22,659
Operating Expenses.................................... (6,448) (10,242) (22,327)
------- -------- --------
Operating Income...................................... 310 301 332
Interest Expense, net................................. (111) (119) (143)
Distribution on Trust Preferred Securities............ (1) -- --
Other Income, net..................................... 8 11 2
Income Tax Expense.................................... (112) (89) (93)
------- -------- --------
Income from Continuing Operations..................... 94 104 98
Loss from Discontinued Operations..................... -- (4) (24)
------- -------- --------
Net Income.................................. $ 94 $ 100 $ 74
======= ======== ========
2000 Compared to 1999. RERC's net income for 2000 was $74 million compared
to net income of $100 million in 1999. The $26 million decrease in net income
was primarily due to:
- a decline in operating income of the Natural Gas Distribution segment,
- an after-tax impairment loss of $17 million on marketable equity
securities classified as "available-for-sale" incurred in 2000 by the
Other Operations segment,
- increased third-party interest expense primarily resulting from higher
levels of short-term borrowings and long-term debt during 2000 compared
to 1999, and
- increased start-up costs of the European trading and marketing operations
in 2000 included in loss from discontinued operations.
The above items were partially offset by improved operating results from
the Wholesale Energy segment's trading and marketing operations in North
America, increased operating income from the Pipelines and Gathering segment,
increased interest income earned on margin deposits on energy trading activities
and income resulting from a tax refund in 2000.
During 2000, RERC incurred a pre-tax impairment loss of $27 million on
marketable equity securities classified as "available-for-sale" by the Other
Operations segment. Management's determination to recognize this impairment
resulted from a combination of events occurring in 2000 related to this
investment. These events affecting the investment included changes occurring in
the investment's senior management, announcement of significant restructuring
charges and related downsizing for the entity, reduced earnings estimates for
this entity by brokerage analysts and the bankruptcy of a competitor of the
investment in the first quarter of 2000. These events, coupled with the stock
market value of RERC's investment in these securities continuing to be below
RERC's cost basis, caused management to believe the decline in fair value to be
other than temporary. This investment is held by Arkla Finance which was
transferred to Reliant Resources effective December 31, 2000.
Operating income increased in 2000 by $31 million, or 10%, from 1999. The
increase was primarily due to significantly improved operating margins (revenues
less natural gas and purchased power expenses) from the Wholesale Energy
segment's trading and marketing activity in the western U.S. market (primarily
California and Nevada), increased operating margins (revenues less natural gas
expenses) from the Natural Gas
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Distribution segment and increased gathering and processing revenues from the
Pipelines and Gathering segment. These items were partially offset by increased
operating expenses, including:
- costs incurred in connection with non-rate regulated retail natural gas
business activities outside RERC's established market areas, which have
been discontinued,
- additional provisions against receivable balances resulting from the
implementation of a new billing system for Reliant Energy Arkla,
- increased costs associated with higher staffing levels to support
increased sales and expanded trading and marketing efforts,
- increased depreciation expenses of the Natural Gas Distribution segment,
and
- increased benefit expense related to an updated actuarial valuation of
employee benefit plans.
RERC's operating revenues for 2000 were $22.7 billion compared to $10.5
billion for 1999. The $12.2 billion, or 115%, increase was primarily due to the
increase in the Wholesale Energy segment's trading and marketing revenues from
increased trading volumes for power and natural gas, as well as higher sale
prices for these commodities.
RERC's operating expenses for 2000 were $22.3 billion compared to $10.2
billion in 1999. The $12.1 billion, or 118%, increase was primarily due to an
increase in volumes and cost of purchased power and natural gas, as discussed
above. Other operating expenses also increased due to the increase in expenses
discussed above.
RERC's effective tax rate in 2000 was 49% compared to 46% in 1999. This
increase was primarily due to an increase in state income taxes in 2000 as
compared to 1999.
RERC is reporting the results of RE Europe Trading as discontinued
operations for all periods presented in RERC's consolidated financial statements
in accordance with Accounting Principles Board Opinion No. 30. For additional
information, please read Note 13 to RERC's consolidated financial statements.
The European Energy segment was created in the fourth quarter of 1999 with the
acquisition of N.V. UNA by a subsidiary of Reliant Energy. Beginning in the
second half of 2000, the European Energy segment's trading and marketing
operations began participating in the emerging wholesale energy trading and
marketing industry in Northwest Europe. Losses from discontinued operations in
1999 and 2000 are primarily related to start-up costs for the European trading
and marketing operations. For additional information regarding the operating
results of the other entities transferred to Reliant Resources, please read Note
13 to RERC's consolidated financial statements.
1999 Compared to 1998. RERC's net income for 1999 was $100 million
compared to net income of $94 million in 1998. The $6 million increase was
primarily due to:
- a significant increase in operating margins of the Wholesale Energy
segment's trading and marketing operations, and
- a decrease in RERC's effective tax rate.
The above items were partially offset by decreased earnings in the Natural
Gas Distribution and Pipelines and Gathering segments and increased general
insurance liability expense.
Although results of the Wholesale Energy segment's trading and marketing
operations significantly improved, it continues to incur higher operating
expenses relating to staffing and personnel to support its increased sales and
marketing efforts.
Operating income decreased in 1999 by $9 million, or 3%, from 1998. The
decline was primarily due to increased operating expenses, in particular
employee benefit expenses at the Natural Gas Distribution and Pipelines and
Gathering segments and increased general liability insurance expense. The
decline was partially offset by increased operating income of the Wholesale
Energy segment's trading and marketing operations.
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RERC's operating revenues for 1999 were $10.5 billion compared to $6.8
billion for 1998. The $3.7 billion, or 56%, increase was primarily due to
increased wholesale trading and marketing revenues from increased trading
volumes for power, natural gas and oil, as well as higher sale prices for these
commodities.
RERC's operating expenses for 1999 were $10.2 billion compared to $6.4
billion in 1998. The $3.8 billion, or 59%, increase was primarily attributable
to an increase in volumes and cost of purchased power, natural gas and oil, as
discussed above. In addition, operating expenses also increased due to:
- increased employee benefit expenses for the Natural Gas Distribution and
Pipelines and Gathering segments,
- increased operating expenses to support increased sales and marketing of
the Wholesale Energy segment's trading and marketing operations (as
discussed above), and
- increased general insurance liability expense.
RERC's effective tax rate in 1999 was 46% compared to 54% in 1998. This
decrease was primarily due to a decrease in state income taxes in 1999 as
compared to 1998.
NEW ACCOUNTING PRONOUNCEMENTS
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- New Accounting Pronouncements" in Item 7
of Reliant Energy's 2000 Form 10-K, which section is incorporated by reference
herein, and Note 2(q) to RERC's consolidated financial statements, for
discussion of new accounting issues that affect RERC.
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES
o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(f) Regulatory Assets.
RERC applies the accounting policies established in Statement of Financial
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types
of Regulation" (SFAS No. 71) to the accounts of the utility operations of
Natural Gas Distribution and MRT. As of December 31, 1999 and 2000, RERC had
recorded $4 million and $5 million, respectively, of net regulatory assets.
If, as a result of changes in regulation or competition, RERC'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), RERC would be required to write off or write down these
regulatory assets and liabilities. In addition, RERC would be required to
determine any impairment to the carrying costs of plant and inventory assets.
o (4) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
Historically, RERC offered energy price risk management services primarily
related to natural gas, electric power and other energy related commodities,
through Reliant Energy Services. As discussed in Note 1, effective December 31,
2000, Reliant Energy Services is no longer a part of RERC. RERC provided 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
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payments to, or receipts of payments from, counterparties based on the
differential between industry pricing publications or exchange quotations.
RERC applied 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 estimated fair value of Trading
Derivatives at December 31, 1999 are presented below (volumes in billions of
British thermal units equivalent (Bbtue) and dollars in millions):
VOLUME-FIXED
VOLUME-FIXED PRICE MAXIMUM
PRICE PAYOR 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
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
==== ==== ==== ====
- ---------------
(1) Computed using the ending balance of each quarter.
In addition to the fixed-price notional volumes above, RERC also had
variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue as of
December 31, 1999. 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
RERC's exposure to market or credit risks.
All of the fair values shown in the table above at December 31, 1999, have
been recognized in income. RERC estimated the fair value as of December 31,
1999, 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, RERC utilized 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 were used to evaluate a contract prior to taking
the position.
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
conditions, market liquidity and RERC'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 was
also inherent in RERC's risk management activities. Credit risk relates to the
risk of loss resulting from non-performance of contractual
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obligations by a counterparty. The following table shows the composition of the
total price risk management assets of RERC as of December 31, 1999.
DECEMBER 31, 1999
------------------
INVESTMENT
GRADE(1) TOTAL
---------- -----
(IN MILLIONS)
Energy marketers............................................ $202 $230
Financial institutions...................................... 90 159
Gas and electric utilities.................................. 220 221
Oil and gas producers....................................... 31 31
Industrials................................................. 3 4
Others...................................................... 174 263
---- ----
Total............................................. $720 908
====
Credit and other reserves................................... (12)
----
Energy price risk management assets......................... $896
====
- ---------------
(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.
(b) Non-trading Activities.
To reduce the risk from market fluctuations in the revenues derived from
the sale of natural gas and related transportation, RERC enters into futures
transactions, forward contracts, swaps and options (Energy Derivatives) in order
to hedge some expected purchases of natural gas and sales of 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. RERC 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 RERC's Statements
of Consolidated Income until the underlying hedged transaction occurs. Once it
becomes probable that an anticipated transaction will not occur, RERC recognizes
deferred gains and losses. In general, the financial impact of transactions
involving these Energy Derivatives is included in RERC's Statements of
Consolidated Income under the captions fuel expenses, in the case of natural gas
transactions and revenues, in the case of natural gas sales transactions. Cash
flows resulting from these transactions in Energy Derivatives are included in
RERC's Statements of Consolidated Cash Flows in the same category as the item
being hedged.
For transactions involving Energy 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, RERC was a fixed-price payor and a fixed-price
receiver in Energy Derivatives covering 29,596 billion British thermal units
(Bbtu) and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, RERC
was a fixed-price payor and a fixed-price receiver in Energy Derivatives
covering 40,991 Bbtu and 14,949 Bbtu of natural gas, respectively. In addition
to the fixed-price notional volumes, RERC also has variable-priced agreements
totaling 41,341 Bbtu and 12,630 Bbtu at December 31, 1999 and 2000,
respectively. The weighted average maturity of these instruments is less than
one year.
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The notional amount is intended to be indicative of RERC'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 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
10 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions at any time in response to changing market
conditions, market liquidity and RERC'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 RERC's risk management activities. Credit risk relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. RERC 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, RERC 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, RERC periodically reviews the
financial condition of these firms in addition to monitoring the effectiveness
of these financial contracts in achieving RERC's objectives. If the
counterparties to these arrangements fail to perform, RERC would seek to compel
performance at law or otherwise obtain compensatory damages. RERC might be
forced to acquire alternative hedging arrangements or be required to replace the
underlying commitment at then-current market prices. In this event, RERC might
incur additional losses to the extent of amounts, if any, already paid to the
counterparties.
RERC's policies prohibit the use of leveraged financial instruments. A
leveraged 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.
Reliant Energy has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including RERC's trading, marketing, power origination
and risk management activities. The committee's duties are to establish RERC's
commodity risk policies, allocate risk capital within limits established by
Reliant Energy's Board of Directors, approve trading of new products and
commodities, monitor risk positions and ensure compliance with Reliant Energy's
risk management policies and procedures and trading limits established by
Reliant Energy's Board of Directors.
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o (9) COMMITMENTS AND CONTINGENCIES
(a) Lease Commitments.
The following table sets forth information concerning RERC's obligations
under non-cancelable long-term operating leases principally consisting of rental
agreements for building space, data processing equipment and vehicles, including
major work equipment (in millions):
2001........................................................ $13
2002........................................................ 8
2003........................................................ 7
2004........................................................ 5
2005........................................................ 4
2006 and beyond............................................. 18
---
Total............................................. $55
===
RERC has a master leasing agreement which provides for the lease of
vehicles, construction equipment, office furniture, data processing equipment
and other property. For accounting purposes, the lease is treated as an
operating lease. At December 31, 2000, the unamortized value of equipment
covered by the master leasing agreement was $10 million. RERC does not expect to
lease additional property under this lease agreement.
Total rental expense for all leases was $25 million, $33 million and $19
million in 1998, 1999 and 2000, respectively.
(b) Transportation Agreement.
A predecessor of Reliant Energy Services had an agreement (ANR Agreement)
with ANR Pipeline Company (ANR) which contemplated that RERC would transfer to
ANR an interest in some of RERC's pipeline and related assets. The interest
represented capacity of 250 Mmcf/day. Under the ANR Agreement, an ANR affiliate
advanced $125 million to RERC. Subsequently, the parties restructured the ANR
Agreement and RERC refunded in 1995 and 1993, respectively, $50 million and $34
million to ANR or an affiliate. Reliant Energy Services recorded a liability
reflecting ANR's or its affiliates' use of 130 Mmcf/day of capacity in some of
RERC's transportation facilities. The level of transportation will decline to
100 Mmcf/day in the year 2003 with a refund of $5 million to an ANR affiliate.
The ANR Agreement will terminate in 2005 with a refund of the $36 million. RERC
has agreed to reimburse Reliant Energy Services for any transportation payments
made under the ANR agreement and for the refund of the $41 million. In RERC's
Consolidated Balance Sheets, RERC has recorded a long-term notes payable to
Reliant Energy Services of $28 million and a deferred obligation to ANR of $13
million as of December 31, 2000.
(c) Environmental Matters.
Manufactured Gas Plant Sites. 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 cleanup 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.
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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 for these accruals 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. RERC 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, RERC has not been able to quantify a range of environmental
expenditures for potential remediation expenditures with respect to other MGP
sites.
Mercury Contamination. RERC'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 RERC at some sites in the past, and RERC has
conducted remediation at sites found to be contaminated. Although RERC 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 RERC and that of others in the natural gas industry to date and on
the current regulations regarding remediation of these sites, RERC believes that
the costs of any remediation of these sites will not be material to RERC's
financial position, results of operations or cash flows.
Potentially Responsible Party Notifications. From time to time RERC 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. Considering the information currently known about
such sites and the involvement of RERC in activities at these sites, RERC does
not believe that these matters will have a material adverse effect on RERC's
financial position, results of operations or cash flows.
(d) Other Legal Matters.
California Wholesale Market. Reliant Energy and Reliant Energy Services
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 in one of the lawsuits. Pursuant to the terms of the master
separation agreement between Reliant Energy and Reliant Resources (see Note 1),
Reliant Resources will agree to indemnify Reliant Energy and RERC Corp. for any
damages arising under this lawsuit and may elect to defend this lawsuit at
Reliant Resources' own expense. This lawsuit was filed in Superior Court in San
Francisco County in January 2001. While plaintiffs alleged various violations by
the defendants of the state antitrust laws and state laws against unfair and
unlawful business practices, this lawsuit 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 this lawsuit seek 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.
Defendants have filed petitions to remove this case to federal court.
Furthermore, defendants have filed a motion with the Panel on Multidistrict
Litigation seeking transfer and consolidation of all the cases. This lawsuit has
only recently been filed. Therefore, the ultimate outcome of this lawsuit cannot
be predicted with any degree of certainty at this time. However, RERC Corp. does
not believe, based on its analysis to date of the claims asserted in this
lawsuit, the indemnification agreement with Reliant Resources and the underlying
facts, that resolution of this lawsuit will have a material adverse effect on
RERC's financial condition, results of operations or cash flows.
RERC is a party to litigation (other than that specifically noted) which
arises in the normal course of business. Management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. Management believes that the effects, if
any, from the disposition of these matters will not have a material adverse
effect on RERC's financial position, results of operations or cash flows.
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