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EXHIBIT 99.a
RELIANT ENERGY INCORPORATED
Items Incorporated by Reference
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K:
o ITEM 3. LEGAL PROCEEDINGS
(a) Reliant Energy.
For a description of certain legal and regulatory proceedings affecting
the Company, see Notes 3, 4, 14(h) and 14(i) to the Company's Consolidated
Financial Statements, which notes are incorporated herein by reference.
o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS OF THE COMPANY -- CERTAIN FACTORS AFFECTING
FUTURE EARNINGS OF THE COMPANY
Earnings for the past three years are not necessarily indicative of
future earnings and results. The level of future earnings depends on numerous
factors including (i) state and federal legislative or regulatory developments,
(ii) national or regional economic conditions, (iii) industrial, commercial and
residential growth in service territories of the Company, (iv) the timing and
extent of changes in commodity prices and interest rates, (v) weather variations
and other natural phenomena, (vi) growth in opportunities for the Company's
diversified operations, (vii) the results of financing efforts, (viii) the
ability to consummate and timing of consummation of pending acquisitions and
dispositions, (ix) the speed, degree and effect of continued electric industry
restructuring in North America and Western Europe, and (x) risks incidental to
the Company's overseas operations, including the effects of fluctuations in
foreign currency exchange rates.
In order to adapt to the increasingly competitive environment, the
Company continues to evaluate a wide array of potential business strategies,
including business combinations or acquisitions involving other utility or
non-utility businesses or properties, internal restructuring, reorganizations or
dispositions of currently owned businesses and new products, services and
customer strategies.
COMPETITION AND RESTRUCTURING OF THE TEXAS ELECTRIC UTILITY INDUSTRY
The electric utility industry is becoming increasingly competitive due
to changing government regulations, technological developments and the
availability of alternative energy sources.
Texas Electric Choice Plan. In June 1999, the Texas legislature adopted
legislation that substantially amends the regulatory structure governing
electric utilities in Texas in order to allow retail competition beginning with
respect to pilot projects for up to 5% of each utility's load in all customer
classes in June 2001 and for all other customers on January 1, 2002. In
preparation for that competition, the Company expects to make significant
changes in the electric utility operations it conducts through Reliant Energy
HL&P. Under the Legislation, on January 1, 2002, most retail customers of
investor-owned electric utilities in Texas will be entitled to purchase their
electricity from any of a number of "retail electric providers" which will
have been certified by the Texas Utility Commission. Power generators will sell
electric energy to wholesale purchasers, including retail electric providers, at
unregulated rates beginning January 1, 2002. For further information regarding
the Legislation, see Note 3 to the Company's Consolidated Financial Statements.
Stranded Costs. 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 return formula will
be applied in a manner to accelerate depreciation of generation related plant
assets for regulatory purposes. In addition, depreciation expense for
transmission and
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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 stranded costs. Any
stranded costs not recovered through the securitization bonds will be recovered
through a non-bypassable charge to transmission and distribution customers.
Accounting. At June 30, 1999, the Company performed an impairment test
of its 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", on a plant specific basis. The Company determined that $797
million of electric generation assets were impaired as of June 30, 1999. Of such
amounts, $745 million relate to the South Texas Project and $52 million relate
to two gas-fired generation plants. The Legislation provides recovery of this
impairment through regulated cash flows during the transition period and
through non-bypassable charges to transmission and distribution customers. As
such, a regulatory asset has been recorded for an amount equal to the
impairment loss and is included on the Company's Consolidated Balance Sheets as
a regulatory asset.
The 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 difference between the fair market
value and the regulatory net book value of the generation assets (as defined by
the Legislation) will either be refunded or collected through future
transmission and distribution rates. This final reconciliation allows
alternative methods of third party valuation of the fair market value of these
assets, including outright sale, stock valuations and asset exchanges. Because
generally accepted accounting principles require the Company to estimate fair
market values on a plant-by-plant basis in advance of the final reconciliation,
the financial impacts of the Legislation with respect to stranded costs are
subject to material changes. Factors affecting such change may include
estimation risk, uncertainty of future energy 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
deferred debits created from discontinuance of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation" pursuant to the Legislation no longer
probable, the Company will write off the corresponding balance of such assets as
a non-cash charge against earnings.
In the fourth quarter of 1999, Reliant Energy HL&P filed an application
to securitize its generation related regulatory assets as defined by the
Legislation. The Texas Utility Commission, Reliant Energy HL&P and other
interested parties have been discussing proposed methodologies for calculating
the amount of such assets to be securitized. The parties have reached an
agreement in principle as to the amount to be securitized, which reflects the
economic value of the nominal book amount which prior to the deregulation
legislation would have been collected through rates over a much longer time
period. The Company has determined that a pre-tax accounting loss of $282
million exists. Therefore, the Company recorded an after-tax extraordinary loss
of $183 million for this accounting impairment of these regulatory assets in
1999.
Transmission System Open Access. In February 1996, the Texas Utility
Commission adopted rules granting third-party users of transmission systems open
access to such systems at rates, terms and conditions comparable to those
available to utilities owning such transmission assets. Under the Texas Utility
Commission order implementing the rule, Reliant Energy HL&P was required to
separate, on an operational basis, its wholesale power marketing operations from
the operations of the transmission grid and, for purposes of transmission
pricing, to disclose each of its separate costs of generation, transmission and
distribution. Within ERCOT, an independent system operator (ISO) manages the
state's electric grid, ensuring system reliability and providing
non-discriminatory transmission access to all power producers and traders.
Transition Plan. In June 1998, the Texas Utility Commission approved the
Transition Plan filed by Reliant Energy HL&P in December 1997. Certain parties
have appealed the order approving the Transition Plan. The provisions of the
Transition Plan expired by their own terms as of December 31, 1999. For
additional information, see Note 4 to the Company's Consolidated Financial
Statements.
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COMPETITION -- RELIANT ENERGY EUROPE OPERATIONS
The European energy market is highly competitive. In addition, over the
next several years, an increasing consolidation of the participants in the Dutch
generating market is expected to occur.
Reliant Energy Europe competes 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 Germany. 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 including interconnections with Norway and the United Kingdom. The
Belgian interconnections are used to import electricity from France but a larger
portion of Dutch imports comes from Germany. In 1998, net power imports into the
Netherlands were approximately 11.7 terawatt hours. Based on current
information, it is estimated that net power imports into the Netherlands in 1999
increased significantly from 1998.
In 1999, UNA and the three other largest Dutch generators supplied
approximately 60% of the electricity consumed in the Netherlands. Smaller Dutch
producers supplied about 28% and the remainder was imported. The Dutch
electricity market is expected to be gradually opened for wholesale competition
including certain commercial and industrial customers beginning in 2001.
Competition is expected to increase in subsequent years and it is anticipated
that the market for small businesses and residential customers will become open
to competition by 2007. The timing of the opening of these markets is subject,
however, to change at the discretion of the Minister of Economic Affairs.
The trading and marketing operations of Reliant Energy Europe will also be
subject to increasing levels of competition. As of March 1, 2000, there were
approximately 25 trading and marketing companies registered with the Amsterdam
Power Exchange. Competition for marketing customers is intense and is expected
to increase with the deregulation of the market. The primary elements of
competition in both the generation and trading and marketing side of Reliant
Energy Europe's business operations are price, credit-support and supply and
delivery reliability.
COMPETITION -- OTHER OPERATIONS
Wholesale Energy. By the third quarter of 2000, Reliant Energy expects that
the Company will own and operate over 8,000 MW of non-rate regulated electric
generation assets that serve the wholesale energy markets located in the states
of California and Florida, and the Southwest, Midwest and Mid-Atlantic regions
of the United States. Competitive factors affecting the results of operations of
these generation assets include: new market entrants, construction by others of
more efficient generation assets, the actions of regulatory authorities and
weather.
Other competitors operate power generation projects in most of the regions
where the Company has invested in non-rate regulated generation assets. Although
local permitting and siting issues often reduce the risk of a rapid growth in
supply of generation capacity in any particular region, over time, projects are
likely to be built which will increase competition and lower the value of some
of the Company's non-rate regulated electric generation assets.
The regulatory environment of the wholesale energy markets in which the
Company invests may adversely affect the competitive conditions of those
markets. In several regions, notably California and in the PJM Power Pool Region
(in the Mid-Atlantic region of the United States), the independent system
operators have chosen to rely on price caps and market redesigns as a way of
minimizing market volatility.
The results of operations of the Company's non-rate regulated generation
assets are also affected by the weather conditions in the relevant wholesale
energy markets. Extreme seasonal weather conditions typically increase the
demand for wholesale energy. Conversely, mild weather conditions typically have
the opposite effect. In some regions, especially California, weather conditions
associated with hydroelectric generation resources such as rainfall and snowpack
can significantly influence market prices for electric power by increasing or
decreasing the availability and timing of hydro-based generation which is
imported into the California market.
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Competition for acquisition of international and domestic non-rate
regulated power projects is intense. The Company competes against a number of
other participants in the non-utility power generation industry, some of which
have greater financial resources and have been engaged in non-utility power
projects for periods longer than the Company and have accumulated larger
portfolios of projects. Competitive factors relevant to the non-utility power
industry include financial resources, access to non-recourse funding and
regulatory factors.
Reliant Energy Services competes for sales in its natural gas, electric
power and other energy derivatives trading and marketing business with other
energy merchants, producers and pipelines based on its 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. Reliant Energy Services also competes against other
energy marketers on the basis of its relative financial position and access to
credit sources. This competitive factor reflects the tendency of energy
customers, wholesale energy suppliers and transporters to seek financial
guarantees and other assurances that their energy contracts will be satisfied.
As pricing information becomes increasingly available in the energy trading and
marketing business and as deregulation in the electricity markets continues to
accelerate, the Company anticipates that Reliant Energy Services will experience
greater competition and downward pressure on per-unit profit margins in the
energy marketing industry.
Natural Gas Distribution. Natural Gas Distribution competes primarily with
alternate energy sources such as electricity and other fuel sources. In
addition, as a result of federal regulatory changes affecting interstate
pipelines, it has become possible for other natural gas suppliers and
distributors to bypass Natural Gas Distribution's facilities and market, sell
and/or transport natural gas directly to small commercial and/or large volume
customers.
Interstate Pipelines. The Interstate Pipelines 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. Interstate Pipelines
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 served by Interstate Pipelines and the level of
competition for transport and storage services.
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
For information regarding the Company's exposure to risk as a result of
fluctuations in commodity prices and derivative instruments, see "Quantitative
and Qualitative Disclosures About Market Risk" in Item 7A of this Report.
INDEXED DEBT SECURITIES (ACES AND ZENS) AND TIME WARNER INVESTMENT
For information on Reliant Energy's indexed debt securities and its
investment in TW Common, see "Quantitative and Qualitative Disclosures About
Market Risk" in Item 7A of this Report and Note 8 to the Company's Consolidated
Financial Statements.
IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES
In 1997, the Company initiated a corporate-wide Year 2000 project to
address mainframe application systems, information technology (IT) related
equipment, system software, client-developed applications, building controls and
non-IT embedded systems such as process controls for energy production and
delivery. The evaluation of Year 2000 issues included those related to
significant customers, key vendors, service suppliers and other parties material
to the Company's operations.
Remediation and testing of all systems and equipment were completed during
1999. The Company did not experience any Year 2000 problems that significantly
affected the operations of the Company. The Company will
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continue to monitor and assess potential future problems. Total direct costs of
resolving the Year 2000 issue with respect to the Company were $29 million.
The Company is in the process of implementing SAP America, Inc.'s (SAP)
proprietary R/3 enterprise software. Although the implementation of the SAP
system had the incidental effect of negating the need to modify many of the
Company's computer systems to accommodate the Year 2000 problem, the Company
does not deem the costs of the SAP system as directly related to its Year 2000
compliance program. Portions of the SAP system were implemented in December
1998, March 1999 and September 1999, and it is expected that the final portion
of the SAP system will be fully implemented by the fourth quarter of 2002. The
cost of implementing the SAP system is currently estimated to be approximately
$237 million, inclusive of internal costs. As of December 31, 1999, $192 million
has been spent on the implementation.
ENTRY INTO THE EUROPEAN MARKET
Reliant Energy Europe owns, operates and sells power from generation
facilities in the Netherlands and plans to participate in the emerging wholesale
energy trading and marketing industry in the Netherlands and other countries in
Europe. Reliant Energy expects that the Dutch electric industry will undergo
change in response to market deregulation in 2001. These expected changes
include the anticipated expiration of certain transition agreements which have
governed the basic tariff rates that UNA and other generators have charged their
customers. Based on current forecasts and other assumptions, the revenues of
UNA could decline significantly from 1999 revenues after 2000.
One of the factors that could have a significant impact on the Dutch energy
industry, including the operations of UNA, is the ultimate resolution of
stranded cost issues in the Netherlands. The Dutch government is currently
seeking to establish a transitional regime in order to solve the problem of
stranded costs, which relate primarily to investments and contracts entered into
by SEP and certain licensed generators prior to the liberalization of the
market. SEP is owned in equal shares by each of the four large Dutch generating
companies, including UNA.
In connection with the acquisition of UNA, the selling shareholders of UNA
agreed to indemnify UNA for certain stranded costs in an amount not to exceed
NLG 1.4 billion (approximately $639 million based on an exchange rate of 2.19
NLG per U.S. dollar as of December 31, 1999), which may be increased in certain
circumstances at the option of the Company up to NLG 1.9 billion (approximately
$868 million). Of the total consideration paid by the Company for the shares of
UNA, NLG 900 million (approximately $411 million) has been placed by the selling
shareholders in an escrow account to secure the indemnity obligations. Although
Reliant Energy believes that the indemnity provision will be sufficient to cover
UNA's ultimate share of any stranded cost obligation, this belief is based on
numerous assumptions regarding the ultimate outcome and timing of the resolution
of the stranded cost issue, the existing shareholders timely performance of
their obligations under the indemnity arrangement, and the amount of stranded
costs which at present is not determinable.
The Dutch government is expected to propose a legislative initiative
regarding stranded costs to the Dutch cabinet in March 2000. The proposed
legislation will be sent to the Dutch council of state for review. It is not
anticipated that the legislation will be reviewed by parliament until late in
the summer of 2000.
For information about the Company's exposure through its investment in
Reliant Energy Europe to losses resulting from fluctuations in currency rates,
see "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of
this Form 10-K.
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RISK OF OPERATIONS IN EMERGING MARKETS
Reliant Energy Latin America's operations are subject to various risks
incidental to investing or operating in emerging market countries. These risks
include political risks, such as governmental instability, and 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. The Company's Latin American operations are
also highly capital intensive and, thus, dependent to a significant extent on
the continued availability of bank financing and other sources of capital on
commercially acceptable terms.
Impact of Currency Fluctuations on Company Earnings. The Company owns
11.78% of the stock of Light Servicos de Eletricidade S.A. (Light) and, through
its investment in Light, a 9.2% interest in the stock of Metropolitana
Electricidade de Sao Paulo S.A. (Metropolitana). As of December 31, 1999 and
1998, Light and Metropolitana had total borrowings of $2.9 billion and $3.2
billion, respectively, denominated in non-local currencies. During the first
quarter of 1999, the Brazilian real was devalued and allowed to float against
other major currencies. The effects of devaluation on the non-local currency
denominated borrowings caused the Company to record an after-tax charge for the
year ended December 31, 1999 of $102 million as a result of foreign currency
transaction losses recorded by both Light and Metropolitana in such periods. For
additional information regarding the effect of the devaluation of the Brazilian
real, see Note 7(a) in the Company's Consolidated Financial Statements.
Light's and Metropolitana's tariff adjustment mechanisms are not directly
indexed to the U.S. dollar or other non-local currencies. To partially offset
the devaluation of the Brazilian real, and the resulting increased operating
costs and inflation, Light and Metropolitana received tariff rate increases of
16% and 21%, respectively, which were phased in during June and July 1999. Light
also received its annual rate adjustment in November 1999 resulting in a tariff
rate increase of 11%. The Company is pursuing additional tariff increases to
mitigate the impact of the devaluation; however, there can be no assurance that
such adjustments will be timely or that they will permit substantial recovery of
the impact of the devaluation.
Certain of Reliant Energy Latin America's other foreign electric
distribution companies have incurred U.S. dollar and other non-local currency
indebtedness (approximately $600 million at December 31, 1999). For further
analysis of foreign currency fluctuations in the Company's earnings and cash
flows, see "Quantitative and Qualitative Disclosures About Market Risk --
Foreign Currency Exchange Rate Risk" in Item 7A of this Form 10-K.
Impact of Foreign Currency Devaluation on Projected Capital Resources. The
ability of Light and Metropolitana to repay or refinance their debt obligations
at maturity is dependent on many factors, including local and international
economic conditions prevailing at the time such debt matures. If economic
conditions in the international markets continue to be unsettled or deteriorate,
it is possible that Light, Metropolitana and the other foreign electric
distribution companies in which the Company holds investments might encounter
difficulties in refinancing their debt (both local currency and non-local
currency borrowings) on terms and conditions that are commercially acceptable to
them and their shareholders. In such circumstances, in lieu of declaring a
default or extending the maturity, it is possible that lenders might seek to
require, among other things, higher borrowing rates, and additional equity
contributions and/or increased levels of credit support from the shareholders of
such entities. For a discussion of the Company's anticipated capital
contributions in 2000, see "-- Liquidity and Capital Resources -- Future Sources
and Uses of Cash Flows -- Reliant Energy Latin America Capital Contributions and
Advances." In 2000, $1.6 billion of debt obligations of Light and Metropolitana
will mature. The availability or terms of refinancing such debt cannot be
assured. Currency fluctuation and instability affecting Latin America may also
adversely affect the Company's ability to refinance its equity investments with
debt.
ENVIRONMENTAL EXPENDITURES
The Company is subject to numerous environmental laws and regulations,
which require it 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.
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Clean Air Act Expenditures. The Company expects the majority of capital
expenditures associated with environmental matters to be incurred by Electric
Operations in connection with new emission limitations under the Federal Clean
Air Act (Clean Air Act) for oxides of nitrogen (NOx). NOx reduction costs
incurred by Electric Operations generating units in the Houston, Texas area
totaled approximately $7 million in 1999 and $7 million in 1998. The Texas
Natural Resources Conservation Commission (TNRCC) is currently considering
additional NOx reduction requirements for electric generating units and other
industrial sources located in the Houston metropolitan area and the eastern half
of Texas as a means to attain the Clean Air Act standard for ozone. Although the
magnitude and timing of these requirements will not be established by the TNRCC
until November, 2000, NOx reductions approaching 90% of the emissions level are
anticipated. Expenditures for NOx controls on Electric Operations' generating
units have been estimated at $500 million to $600 million during the period 2000
through 2003, with an estimated $80 million to be incurred during 2000. In
addition, the Legislation created a program mandating air emissions reductions
for certain generating facilities of Electric Operations. The Legislation
provides for stranded cost recovery for costs associated with this obligation
incurred before May 1, 2003. For further information regarding the Legislation,
see Note 3 to the Company's Consolidated Financial Statements.
Site Remediation Expenditures. From time to time the Company has received
notices from regulatory authorities or others regarding its 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, Reliant Energy believes that remediation costs
will not materially affect its 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 Reliant Energy's estimates. For
information about specific sites that are the subject of remediation claims,
see Note 14(h) to the Company's Consolidated Financial Statements and Note 8(d)
to Resources' Consolidated Financial Statements.
Mercury Contamination. Like other natural gas pipelines, the Company's
pipeline operations have in the past employed elemental mercury in meters used
on its pipelines. Although the mercury has now been removed from the meters, it
is possible that small amounts of mercury have been spilled at some of those
sites in the course of normal maintenance and replacement operations and that
such spills have contaminated the immediate area around the meters with
elemental mercury. Such contamination has been found by Resources at some sites
in the past, and the Company has conducted remediation at sites found to be
contaminated. Although the Company is not aware of additional specific sites, it
is possible that other contaminated sites exist and that remediation costs will
be incurred for such sites. Although the total amount of such costs cannot be
known at this time, based on experience of the Company and others in the natural
gas industry to date and on the current regulations regarding remediation of
such sites, the Company believes that the cost of any remediation of such sites
will not be material to the Company's or Resources' financial position, results
of operations or cash flows.
Other. In addition, the Company has been named as a defendant in litigation
related to such sites and in recent years has been named, along with numerous
others, as a defendant in several lawsuits filed by a large number of
individuals who claim injury due to exposure to asbestos while working at sites
along the Texas Gulf Coast. Most of these claimants have been workers who
participated in construction of various industrial facilities, including power
plants, and some of the claimants have worked at locations owned by the Company.
The Company anticipates that additional claims like those received may be
asserted in the future and intends to continue its practice of vigorously
contesting claims which it does not consider to have merit. Although their
ultimate outcome cannot be predicted at this time, the Company does not believe,
based on its experience to date, that these matters, either individually or in
the aggregate, will have a material adverse effect on the Company's financial
position, results of operations or cash flows.
OTHER CONTINGENCIES
For a description of certain other legal and regulatory proceedings
affecting the Company, see Notes 3, 4 and 14 to the Company's Consolidated
Financial Statements and Note 8 to Resources' Consolidated Financial Statements.
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o Item 7.A QUANTATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
INTEREST RATE RISK
The Company has long-term debt, Company obligated mandatorily
redeemable preferred securities of subsidiary trusts holding solely junior
subordinated debentures of the Company (Trust Preferred Securities), securities
held in the Company's nuclear decommissioning trust, bank facilities, certain
lease obligations and interest rate swaps which subject the Company to the risk
of loss associated with movements in market interest rates.
At December 31, 1999, the Company had issued fixed-rate debt (excluding
indexed debt securities) and Trust Preferred Securities aggregating $5.8 billion
in principal amount and having a fair value of $5.6 billion. These instruments
are fixed-rate and, therefore, do not expose the Company to the risk of loss in
earnings due to changes in market interest rates (see Notes 10 and 11 to the
Company's Consolidated Financial Statements). However, the fair value of these
instruments would increase by approximately $305 million if interest rates were
to decline by 10% from their levels at December 31, 1999. In general, such an
increase in fair value would impact earnings and cash flows only if the Company
were to reacquire all or a portion of these instruments in the open market prior
to their maturity.
The Company's floating-rate obligations aggregated $3.1 billion at
December 31, 1999 (see Note 10 to the Company's Consolidated Financial
Statements), inclusive of (i) amounts borrowed under short-term and long-term
credit facilities of the Company (including the issuance of commercial paper
supported by such facilities), (ii) borrowings underlying a receivables facility
and (iii) amounts subject to a master leasing agreement under which lease
payments vary depending on short-term interest rates. These floating-rate
obligations expose the Company to the risk of increased interest and lease
expense in the event of increases in short-term interest rates. If the floating
rates were to increase by 10% from December 31, 1999 levels, the Company's
consolidated interest expense and expense under operating leases would increase
by a total of approximately $1.6 million each month in which such increase
continued.
As discussed in Notes 1(l) and 6(c) to the Company's Consolidated
Financial Statements, the Company contributes $14.8 million per year to a trust
established to fund the Company's share of the decommissioning costs for the
South Texas Project. The securities held by the trust for decommissioning costs
had an estimated fair value of $145 million as of December 31, 1999, of which
approximately 40% were fixed-rate debt securities that subject the Company to
risk of loss of fair value with movements in market interest rates. If interest
rates were to increase by 10% from their levels at December 31, 1999, the
decrease in fair value of the fixed-rate debt securities would not be material
to the Company. In addition, the risk of an economic loss is mitigated. Any
unrealized gains or losses are accounted for in accordance with SFAS No. 71 as a
regulatory asset/liability because the Company believes that its future
contributions which are currently recovered through the rate-making process will
be adjusted for these gains and losses. For further discussion regarding the
recovery of decommissioning costs pursuant to the Legislation, see Note 3 to the
Consolidated Financial Statements.
As discussed in Note 1(l) to the Company's Consolidated Financial
Statements, UNA holds fixed-rate debt securities, which had an estimated fair
value of $133 million as of December 31, 1999, that subject the Company to risk
of loss of fair value and earnings with movements in market interest rates. If
interest rates were to increase by 10% from their levels at December 31, 1999,
the decrease in fair value and loss in earnings from this investment would not
be material to the Company.
The Company has entered into interest rate swaps for the purpose of
decreasing the amount of debt subject to interest rate fluctuations. At
December 31, 1999, these interest rate swaps had an aggregate notional amount of
$64 million and the cost to terminate would not result in a material loss in
earnings and cash flows to the Company (see Note 5 to the Company's Consolidated
Financial Statements). An increase of 10% in the December 31, 1999 level of
interest rates would not increase the cost of termination of the swaps by a
material amount to the Company. Swap termination costs would impact the
Company's earnings and cash flows only if all or a portion of the swap
instruments were terminated prior to their expiration.
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As discussed in Note 10(b) to the Company's Consolidated Financial
Statements, in November 1998, Resources sold $500 million aggregate principal
amount of its 6 3/8% TERM Notes which included an embedded option to remarket
the securities. The option is expected to be exercised in the event that the
ten-year Treasury rate in 2003 is below 5.66%. At December 31, 1999, the Company
could terminate the option at a cost of $11 million. A decrease of 10% in the
December 31, 1999 level of interest rates would increase the cost of
termination of the option by approximately $5 million.
EQUITY MARKET RISK
As discussed in Note 8 to the Company's Consolidated Financial
Statements, the Company owns approximately 55 million shares of TW Common, of
which approximately 38 million and 17 million shares are held by the Company to
facilitate its ability to meet its obligations under the ACES and ZENS,
respectively. Unrealized gains and losses resulting from changes in the market
value of the Company's TW Common are recorded in the Consolidated Statement of
Operations. IncreaseS in the market value of TW Common result in an increase in
the liability for the ZENS and ACES and are recorded as a non-cash expense. Such
non-cash expense will be offset by an unrealized gain on the Company's TW Common
investment. However, if the market value of TW Common declines below $58.25, the
ZENS payment obligation will not decline below its original principal amount. As
of December 31, 1999, the market value of TW Common was $72.31 per share. A
decrease of 10% from the December 31, 1999 market value of TW Common would not
result in a loss. As of March 1, 2000, the market value of TW Common was $84.38
per share. In addition, the Company has a $14 million investment in Cisco
Systems, Inc. as of December 31, 1999, which is classified as trading under SFAS
No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
(SFAS No. 115). In January 2000, the Company entered into financial instruments
(a put option and a call option) to manage price risks related to the Company's
investment in Cisco Systems, Inc. A decline in the market value of this
investment would not materially impact the Company's earnings and cash flows.
The Company also has a $9 million investment in Itron, Inc. (Itron) which is
classified as "available for sale" under SFAS No. 115. The Itron investment
exposes the Company to losses in the fair value of Itron common stock. A 10%
decline in the market value per share of Itron common stock from the December
31, 1999 levels would not result in a material loss in fair value to the
Company.
As discussed above under "-- Interest Rate Risk," the Company
contributes to a trust established to fund the Company's share of the
decommissioning costs for the South Texas Project which held debt and equity
securities as of December 31, 1999. The equity securities expose the Company to
losses in fair value. If the market prices of the individual equity securities
were to decrease by 10% from their levels at December 31, 1999, the resulting
loss in fair value of these securities would, not be material to the Company.
Currently, the risk of an economic loss is mitigated as discussed above under
"--Interest Rate Risk."
FOREIGN CURRENCY EXCHANGE RATE RISK
As further described in "Certain Factors Affecting Future Earnings of
the Company -- Risks of Operations in Emerging Markets" in Item 7 of this Form
10-K, the Company has investments in electric generation and distribution
facilities in Latin America with a substantial portion accounted for under the
equity method. In addition, as further discussed in Note 2 of the Company's
Consolidated Financial Statements, during the fourth quarter of 1999, the
Company completed the first and second phases of the acquisition of 52% of the
shares UNA, a Dutch power generation company and completed the final phase of
the acquisition on March 1, 2000. These foreign operations expose the Company to
risk of loss in earnings and cash flows due to the fluctuation in foreign
currencies relative to the Company's consolidated reporting currency, the U.S.
dollar. The Company accounts for adjustments resulting from translation of its
investments with functional currencies other than the U.S. dollar as a charge or
credit directly to a separate component of stockholders' equity. The Company has
entered into foreign currency swaps and has issued Euro denominated debt to
hedge its net investment in UNA. Changes in the value of the swap and debt are
recorded as foreign currency translation adjustments as a component of
stockholders' equity. For further discussion of the accounting for foreign
currency adjustments, see Note 1(m) in the Company's Consolidated Financial
Statements. The cumulative translation loss of $77 million, recorded as of
December 31, 1999, will be realized as a loss in earnings and cash flows only
upon the disposition of the related investments. The cumulative translation loss
was $34 million as of
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December 31, 1998. The increase in cumulative translation loss from December 31,
1998 to December 31, 1999, was primarily due to the impact of devaluation of the
Brazilian real on the Company's investments in Light and Metropolitana.
In addition, certain of Reliant Energy Latin America's foreign
operations have entered into obligations in currencies other than their own
functional currencies which expose the Company to a loss in earnings. In such
cases, as the respective investment's functional currency devalues relative to
the non-local currencies, the Company will record its proportionate share of its
investments' foreign currency transaction losses related to the non-local
currency denominated debt. At December 31, 1999, Light and Metropolitana of
which the Company owns 11.78% and 9.2%, respectively, had total borrowings of
approximately $2.9 billion denominated in non-local currencies. As described in
Note 7 to the Company's Consolidated Financial Statements, in 1999 the Company
reported a $102 million (after-tax) charge to net income and a $43 million
charge to other comprehensive income, due to the devaluation of the Brazilian
real. The charge to net income reflects increases in the liabilities at Light
and Metropolitana for their non-local currency denominated borrowings using the
exchange rate in effect at December 31, 1999 and a monthly weighted average
exchange rate for the year then ended. The charge to other comprehensive income
reflects the translation effect on the local currency denominated net assets
underlying the Company's investment in Light. As of December 31, 1999, the
Brazilian real exchange rate was 1.79 per U.S. dollar. An increase of 10% from
the December 31, 1999 exchange rate would result in the Company recording an
additional charge of $20 million and $23 million to net income and other
comprehensive income, respectively. As of March 1, 2000, the Brazilian real
exchange rate was 1.77 per U.S. dollar.
The Company attempts to manage and mitigate this foreign currency risk
by balancing the cost of financing with local denominated debt against the risk
of devaluation of that local currency and including a measure of the risk of
devaluation in its financial plans. In addition, where possible, Reliant Energy
Latin America attempts to structure its tariffs and revenue contracts to
ensure some measure of adjustment due to changes in inflation and currency
exchange rates; however, there can be no assurance that such efforts will
compensate for the full effect of currency devaluation, if any.
ENERGY COMMODITY PRICE RISK
As further described in Note 5 to the Company's Consolidated Financial
Statements, the Company utilizes a variety of derivative financial instruments
(Derivatives), including swaps, over-the-counter options and exchange-traded
futures and options, as part of the Company's overall hedging strategies and
for trading purposes. To reduce the risk from the adverse effect of market
fluctuations in the price of electric power, natural gas, crude oil and refined
Products and related transportation and transmission, the Company enters into
futures transactions, forward contracts, swaps and options (Energy Derivatives)
in order to hedge certain commodities in storage, as well as certain expected
purchases, sales, transportation and transmission of energy commodities (a
portion of which are firm commitments at the inception of the hedge). The
Company's policies prohibit the use of leveraged financial instruments. In
addition, Reliant Energy Services maintains a portfolio of Energy Derivatives to
provide price risk management services and for trading purposes (Trading
Derivatives).
The Company uses value-at-risk and a sensitivity analysis method for
assessing the market risk of its derivatives.
With respect to the Energy Derivatives (other than Trading Derivatives)
held by the Company as of December 31, 1999, an increase of 10% in the market
prices of natural gas and electric power from year-end levels would have
decreased the fair value of these instruments by approximately $12 million. As
of December 31, 1998, a decrease of 10% in the market prices of natural gas and
electric power from year-end levels would have decreased the fair value of these
instruments by approximately $3 million.
The above analysis of the Energy Derivatives utilized for hedging
purposes does not include the favorable impact that the same hypothetical price
movement would have on the Company's physical purchases and sales of natural gas
and electric power to which the hedges relate. Furthermore, the Energy
Derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value
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of the portfolio of Energy Derivatives held for hedging purposes associated with
the hypothetical changes in commodity prices referenced above would be offset by
a favorable impact on the underlying hedged physical transactions, assuming (i)
the Energy Derivatives are not closed out in advance of their expected term,
(ii) the Energy Derivatives continue to function effectively as hedges of the
underlying risk and (iii) as applicable, anticipated transactions occur as
expected.
The disclosure with respect to the Energy Derivatives relies on the
assumption that the contracts will exist parallel to the underlying physical
transactions. If the underlying transactions or positions are liquidated prior
to the maturity of the Energy Derivatives, a loss on the financial instruments
may occur, or the options might be worthless as determined by the prevailing
market value on their termination or maturity date, whichever comes first.
With respect to the Trading Derivatives held by Reliant Energy Services,
consisting of natural gas, electric power, crude oil and refined products,
weather derivatives, physical forwards, swaps, options and exchange-traded
futures and options, the Company is exposed to losses in fair value due to
changes in the price and volatility of the underlying derivatives. During the
years ended December 31, 1999 and 1998, the highest, lowest and average monthly
value-at-risk in the Trading Derivative portfolio was less than $10 million at a
95% confidence level and for a holding period of one business day. The Company
uses the variance/covariance method for calculating the value-at-risk and
includes delta approximation for option positions.
The Company has established a Risk Oversight Committee comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including derivative trading and hedging activities
discussed above. The committee's duties are to establish the Company's commodity
risk policies, allocate risk capital within limits established by the Company's
board of directors, approve trading of new products and commodities, monitor
risk positions and ensure compliance with the Company's risk management policies
and procedures and the trading limits established by the Company's board of
directors.
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ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES:
o (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(d) Regulatory Assets.
The Company applies the accounting policies established in SFAS No. 71 to
the accounts of transmission and distribution operations of Reliant Energy HL&P
and Natural Gas Distribution and to certain of the accounts of Interstate
Pipelines. For information regarding Reliant Energy HL&P's electric generation
operations' discontinuance of the application of SFAS No. 71 and the effect on
its regulatory assets, see Note 3.
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheet as of December 31, 1999, detailed by
Electric Operations and other segments.
ELECTRIC TOTAL
OPERATIONS OTHER COMPANY
------------ ------------ ------------
(MILLIONS OF DOLLARS)
Recoverable impaired plant costs -- net ................................... $ 587 $ $ 587
Recoverable electric generation related regulatory assets -- net .......... 952 952
Regulatory tax liability -- net ........................................... (45) (45)
Unamortized loss on reacquired debt ....................................... 69 69
Other deferred debits/credits ............................................. (18) 4 (14)
------------ ------------ ------------
Total ................................................................ $ 1,545 $ 4 $ 1,549
============ ============ ============
Included in the above table is $191 million of regulatory liabilities
recorded as other deferred credits in the Company's Consolidated Balance Sheet
as of December 31, 1999, which primarily relates to the over recovery of
Electric Operations' fuel costs, gains on nuclear decommissioning trust funds,
regulatory tax liabilities and excess deferred income taxes.
Under a "deferred accounting" plan authorized by the Public Utility
Commission of Texas (Texas Utility Commission), Electric Operations was
permitted for regulatory purposes to accrue carrying costs in the form of
allowance for funds used during construction (AFUDC) on its investment in the
South Texas Project Electric Generating Station (South Texas Project) and to
defer and capitalize depreciation and other operating costs on its investment
after commercial operation until such costs were reflected in rates. In
addition, the Texas Utility Commission authorized Electric Operations under a
"qualified phase-in plan" to capitalize allowable costs (including return)
deferred for future recovery as deferred charges. These costs are included in
recoverable electric generation related regulatory assets.
In 1991, Electric Operations ceased all cost deferrals related to the South
Texas Project and began amortizing such amounts on a straight-line basis. Prior
to January 1, 1999, the accumulated deferrals for "deferred accounting" were
being amortized over the estimated depreciable life of the South Texas Project.
Starting in 1991, the accumulated deferrals for the "qualified phase-in plan"
were amortized over a ten-year phase-in period. The amortization of all deferred
plant costs (which totaled $26 million for each of the years 1998 and 1997) is
included on the Company's Statements of Consolidated Income as depreciation and
amortization expense. Pursuant to the Legislation (see Note 3), the Company
discontinued amortizing deferred plant costs effective January 1, 1999.
In 1999, 1998 and 1997, the Company, as permitted by the 1995 rate case
settlement (Rate Case Settlement), also amortized $22 million, $4 million and
$66 million (pre-tax), respectively, of its investment in certain lignite
reserves associated with a canceled generating station. The remaining investment
in these reserves of $14 million is included in the above table as a component
of recoverable electric generation related regulatory assets and will be
amortized fully by December 31, 2001.
For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets, see Note 3.
If, as a result of changes in regulation or competition, the Company's
ability to recover these assets and liabilities would not be assured, then
pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the
Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" (SFAS No. 121), the Company would be required to write off or
write down such regulatory assets and liabilities, unless some form of
transition costs recovery continues through rates established and collected
for their remaining regulated operations. In addition, the Company would be
required to determine any impairment to the carrying costs of plant and
inventory assets.
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(m) Foreign Currency Adjustments.
Foreign subsidiaries' assets and liabilities where the local currency is
the functional currency have been translated into U.S. dollars using the
exchange rate at the balance sheet date. Revenues, expenses, gains and losses
have been translated using the weighted average exchange rate for each month
prevailing during the periods reported. Cumulative adjustments resulting from
translation have been recorded in stockholders' equity in other comprehensive
income. However, fluctuations in foreign currency exchange rates relative to the
U.S. dollar can have an impact on the reported equity earnings of the Company's
foreign investments. For additional information about the Company's investments
in Brazil and the devaluation of the Brazilian real in 1999, see Note 7.
When the U.S. dollar is the functional currency, the financial statements
of such foreign subsidiaries are remeasured in U.S. dollars using historical
exchange rates for non-monetary accounts and the current rate at the respective
balance sheet date and the weighted average exchange rate for all other balance
sheet and income statement accounts, respectively. All exchange gains and losses
from remeasurement and foreign currency transactions are included in
consolidated net income.
(2) BUSINESS ACQUISITIONS
During 1999, the Company completed the first two phases of the acquisition
of UNA, a Dutch power generation company. The Company acquired 40% and 12% of
UNA's capital stock on October 7, 1999 and December 1, 1999, respectively. The
aggregate purchase price paid by the Company in connection with the first two
phases consisted of a total of $833 million in cash and $426 million in a
five-year promissory note to UNA. Under the terms of the acquisition agreement,
the Company purchased the remaining shares of UNA on March 1, 2000 for
approximately $975 million. The commitment for this purchase was recorded as a
business purchase obligation in the Consolidated Balance Sheet as of December
31, 1999 based on an exchange rate of 2.19 Dutch guilders (NLG) per U.S. dollar
(the exchange rate on December 31, 1999). A portion ($596 million) of the
business purchase obligation was recorded as a non-current liability as this
portion of the obligation was financed with a three-year term loan facility (see
Note 19). Effective October 1, 1999, the Company has recorded 100% of the
operating results of UNA. The total purchase price, payable in NLG, of
approximately $2.4 billion includes the $426 million promissory note to UNA and
assumes an exchange rate of 2.0565 NLG per U.S. dollar (the exchange rate on
October 7, 1999). The Company recorded the acquisition under the purchase method
of accounting with assets and liabilities of UNA reflected at their estimated
fair values. The excess of the purchase price over the fair value of net assets
acquired of approximately $840 million was recorded as goodwill and is being
amortized over 35 years. On a preliminary basis, the Company's fair value
adjustments included increases in property, plant and equipment, long-term debt,
and related deferred taxes. The Company expects to finalize these fair value
adjustments during 2000; however, it is not anticipated that any additional
adjustments will be material.
In August 1997 , the former parent corporation (Former Parent) of the
Company, merged with and into Reliant Energy, and NorAm Energy Corp., a natural
gas gathering, transmission, marketing and distribution company (Former NorAm),
merged with and into Resources Corp. Effective upon the mergers (collectively,
the Merger), each outstanding share of common stock of Former Parent was
converted into one share of common stock (including associated preference stock
purchase rights) of the Company, and each outstanding share of common stock of
Former NorAm was converted into the right to receive $16.3051 cash or 0.74963
shares of common stock of the Company. The aggregate consideration paid to
Former NorAm stockholders in connection with the Merger consisted of $1.4
billion in cash and 47.8 million shares of the Company's common stock valued at
approximately $1.0 billion. The overall transaction was valued at $4.0 billion
consisting of $2.4 billion for Former NorAm's common stock and common stock
equivalents and $1.6 billion of Former NorAm debt. The Company recorded the
acquisition under the purchase method of accounting with assets and liabilities
of Former NorAm reflected at their estimated fair values. The Company recorded
the excess of the acquisition cost over the fair value of the net assets
acquired of $2.1 billion as goodwill and is amortizing this amount over 40
years. The Company's fair value adjustments included increases in property,
plant and equipment, long-term debt, unrecognized pension and postretirement
benefits liabilities and related deferred taxes.
The Company's results of operations incorporate UNA's and Resources'
results of operations only for the period beginning with the effective date of
their respective acquisition. The following tables present certain actual
financial information for the years ended December 31, 1999, 1998 and 1997;
unaudited pro forma information for the years ended December 31, 1999 and 1998,
as if the acquisition of UNA had occurred on January 1, 1999 and 1998; and
unaudited pro forma information for the year ended December 31, 1997, as if the
Merger with Resources had occurred on January 1, 1997.
ACTUAL AND PRO FORMA COMBINED RESULTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1999 1998 1997
--------------------- ---------------------- ----------------------
ACTUAL PRO FORMA ACTUAL PRO FORMA ACTUAL PRO FORMA
-------- --------- -------- --------- -------- ---------
(UNAUDITED) (UNAUDITED) (UNAUDITED)
Revenues................................. $ 15,303 $15,784 $ 11,488 $ 12,320 $ 6,878 $ 10,191
Net income (loss) attributable to
common stockholders................... 1,482 1,525 (141) (61) 421 437
Basic earnings per share................. 5.20 5.35 (.50) (.21) 1.66 1.55
Diluted earnings per share............... 5.18 5.33 (.50) (.21) 1.66 1.55
These pro forma results are based on assumptions deemed appropriate by the
Company's management, have been prepared for informational purposes only and are
not necessarily indicative of the combined results that would have resulted if
the acquisition of UNA had occurred on January 1, 1999 and 1998 and the Merger
with Resources had occurred on January 1, 1997. Purchase related adjustments to
results of operations include amortization of goodwill and the effects on
depreciation, amortization, interest expense and deferred income taxes of the
assessed fair value of certain UNA and Resources assets and liabilities.
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o (3) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC
GENERATION OPERATIONS
In June 1999, the Texas legislature adopted the Texas Electric Choice Plan
(Legislation). The Legislation substantially amends the regulatory structure
governing electric utilities in Texas in order to allow retail competition
beginning with respect to pilot projects for up to 5% of each utility's load in
all customer classes in June 2001 and for all other customers on January 1,
2002. In preparation for that competition, the Company expects to make
significant changes in the electric utility operations it conducts through
Reliant Energy HL&P. In addition, the Legislation requires the Texas Utility
Commission to issue a number of new rules and determinations in implementing the
Legislation.
The Legislation defines the process for competition and creates a
transition period during which most utility rates are frozen at rates not in
excess of their present levels. The Legislation provides for utilities to
recover their generation related stranded costs and regulatory assets (as
defined in the Legislation).
Retail Choice. Under the Legislation, on January 1, 2002, most retail
customers of investor-owned electric utilities in Texas will be entitled to
purchase their electricity from any of a number of "retail electric providers"
which will have been certified by the Texas Utility Commission. Retail electric
providers will not own or operate generation assets and their sales rates will
not be subject to traditional cost-of-service rate regulation. Retail electric
providers which are affiliates of electric utilities may compete substantially
statewide for these sales, but rates they charge within the affiliated electric
utility's traditional service territory are subject to certain limitations at
the outset of retail choice, as described below. The Texas Utility Commission
will prescribe regulations governing quality, reliability and other aspects of
service from retail electric providers. Transmission between the regulated
utility and its current and future competitive affiliates is subject to
regulatory scrutiny and must comply with a code of conduct established by the
Texas Utility Commission. The code of conduct governs interactions between
employees of
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regulated and current and future unregulated affiliates as well as the exchange
of information between such affiliates.
Unbundling. By January 1, 2002, electric utilities in Texas such as Reliant
Energy HL&P will restructure their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Legislation, the Company submitted a plan in January 2000
to accomplish the required separation of its regulated operations into separate
units and is awaiting approval from the Texas Utility Commission. The
transmission and distribution business will continue to be subject to
cost-of-service rate regulation and will be responsible for the delivery of
electricity to retail consumers.
Generation. Power generators will sell electric energy to wholesale
purchasers, including retail electric providers, at unregulated rates beginning
January 1, 2002. To facilitate a competitive market, Reliant Energy HL&P and
most other electric utilities will be required to sell at auction entitlements
to 15% of their installed generating capacity no later than 60 days before
January 1, 2002. That obligation to auction entitlements continues until the
earlier of January 1, 2007 or the date the Texas Utility Commission determines
that at least 40% of the residential and small commercial load served in the
electric utility's service area is being served by non-affiliated retail
electric providers. In addition, a power generator that owns and controls more
than 20% of the power generation in, or capable of delivering power to, a power
region after the reductions from the capacity auction (calculated as prescribed
in the Legislation) must submit a mitigation plan to reduce generation that it
owns and controls to no more than 20% in the power region. The Legislation also
creates a program mandating air emissions reductions for non-permitted
generating facilities. The Company anticipates that any stranded costs
associated with this obligation incurred before May 1, 2003 will be recoverable
through the stranded cost recovery mechanisms contained in the Legislation.
Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will
be frozen until January 1, 2002. Effective January 1, 2002, retail rates charged
to residential and small commercial customers by the utility's affiliated retail
electric provider will be reduced by 6% from the average rates (on a bundled
basis) in effect on January 1, 1999. That reduced rate will be known as the
"price to beat" and will be charged by the affiliated retail electric provider
to residential and small commercial customers in Reliant Energy HL&P's service
area who have not elected service from another retail electric provider. The
affiliated retail electric provider may not offer different rates to residential
or small commercial customer classes in the utility's service area until the
earlier of the date the Texas Utility Commission determines that 40% of power
consumed by that class is being served by non-affiliated retail electric
providers or January 1, 2005. In addition, the affiliated retail electric
provider must make the price to beat available to eligible consumers until
January 1, 2007.
Stranded Costs. Reliant Energy HL&P will be entitled to recover its
stranded costs (i.e., the excess of net book value of generation assets (as
defined by the Legislation) over the market value of those assets) and its
regulatory assets related to generation. The Legislation prescribes specific
methods for determining the amount of stranded costs and the details for their
recovery. However, during the base rate freeze period from 1999 through 2001,
earnings above the utility's authorized return formula will be applied in a
manner to accelerate depreciation of generation related plant assets for
regulatory purposes. In addition, depreciation expense for transmission and
distribution related assets may be redirected to generation assets for
regulatory purposes during that period.
The Legislation provides for Reliant Energy HL&P, or a special purpose
entity, to issue securitization bonds for the recovery of generation related
regulatory assets and stranded costs. These bonds will be sold to third parties
and will be amortized through non-bypassable charges to transmission and
distribution customers. Any stranded costs not recovered through the
securitization bonds will be recovered through a non-bypassable charge to
transmission and distribution customers. Costs associated with nuclear
decommissioning that have not been recovered as of January 1, 2002, will
continue to be subject to cost-of-service rate regulation and will be included
in a non-bypassable charge to transmission and distribution customers.
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In November 1999, Reliant Energy HL&P filed an application with the Texas
Utility Commission requesting a financing order authorizing the issuance by a
special purpose entity organized by the Company, pursuant to the Legislation, of
transition bonds related to Reliant Energy HL&P's generation-related regulatory
assets. The Company believes the Texas Utility Commission will authorize the
issuance of approximately $750 million of transition bonds. Payments on the
transition bonds will be made out of funds derived from non-bypassable
transition charges to Reliant Energy HL&P's transmission and distribution
customers. The offering and sale of the transition bonds will be registered
under the Securities Act of 1933 and, absent any appeals, are expected to be
consummated in the second or third quarter of 2000.
Accounting. Historically, Reliant Energy HL&P has applied the accounting
policies established in SFAS No. 71. In general, SFAS No. 71 permits a company
with cost-based rates to defer certain costs that would otherwise be expensed to
the extent that it meets the following requirements: (1) its rates are regulated
by a third party; (2) its rates are cost-based; and (3) there exists a
reasonable assumption that all costs will be recoverable from customers through
rates. When a company determines that it no longer meets the requirements of
SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write
off regulatory assets and liabilities unless some form of recovery continues
through rates established and collected from remaining regulated operations. In
addition, such company is required to determine any impairment to the carrying
costs of deregulated plant and inventory assets in accordance with SFAS No. 121.
In July 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus on Issue No. 97-4, "Deregulation
of the Pricing of Electricity - Issues Related to the Application of FASB
Statements No. 71, Accounting for the Effects of Certain Types of Regulation,
and No. 101, Regulated Enterprises Accounting for the Discontinuation of
Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded
that a company should stop applying SFAS No. 71 to a segment which is subject to
a deregulation plan at the time the deregulation legislation or enabling rate
order contains sufficient detail for the utility to reasonably determine how the
plan will affect the segment to be deregulated. In addition, EITF No. 97-4
requires that regulatory assets and liabilities be allocated to the applicable
portion of the electric utility from which the source of the regulated cash
flows will be derived.
The Company believes that the Legislation provides sufficient detail
regarding the deregulation of the Company's electric generation operations to
require it to discontinue the use of SFAS No. 71 for those operations. Effective
June 30, 1999, the Company applied SFAS No. 101 to its electric generation
operations. Reliant Energy HL&P's transmission and distribution operations
continue to meet the criteria of SFAS No. 71.
In 1999, the Company evaluated the recovery of its generation related
regulatory assets and liabilities. The Company determined that a pre-tax
accounting loss of $282 million exists because it believes only the economic
value of its generation related regulatory assets (as defined by the
Legislation) will be recovered. Therefore, the Company recorded a $183 million
after-tax extraordinary loss in the fourth quarter of 1999. If events were to
occur that made the recovery of certain of the remaining generation related
regulatory assets no longer probable, the Company would write off the remaining
balance of such assets as a non-cash charge against earnings. Pursuant to EITF
No. 97-4, the remaining recoverable regulatory assets will not be written off
and will become associated with the transmission and distribution portion of the
Company's electric utility business. For details regarding the Reliant Energy
HL&P's regulatory assets, see Note 1 (d).
At June 30, 1999, the Company performed an impairment test of its
previously regulated electric generation assets pursuant to SFAS No. 121 on a
plant specific basis. Under SFAS No. 121, an asset is considered impaired, and
should be written down to fair value, if the future undiscounted net cash flows
expected to be generated by the use of the asset are insufficient to recover the
carrying amount of the asset. For assets that are impaired pursuant to SFAS No.
121, the Company determined the fair value for each generating plant by
estimating the net present value of future cash inflows and outflows over the
estimated life of each plant. The difference between fair value and net book
value was recorded as a reduction in the current book value. The Company
determined that $797 million of
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electric generation assets were impaired as of June 30, 1999. Of such amounts,
$745 million relates to the South Texas Project and $52 million relates to two
gas-fired generation plants. The Legislation provides recovery of this
impairment through regulated cash flows during the transition period and through
non-bypassable charges to transmission and distribution customers. As such, a
regulatory asset has been recorded for an amount equal to the impairment loss
and is included on the Company's Consolidated Balance Sheets as a regulatory
asset. In addition, the Company recorded an additional $12 million of
recoverable impaired plant costs in the third quarter of 1999 related to
previously incurred costs that are now estimated to be recoverable pursuant to
the Legislation. During the third and fourth quarter of 1999, the Company
recorded amortization expense relate to the recoverable impaired plant costs and
other deferred debits created from discontinuing SFAS No. 71 of $221 million.
The Company will continue to amortize this regulatory asset as it is recovered
from regulated cash flows.
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 difference between the fair market
value and the regulatory net book value of the generation assets (as defined by
the Legislation) will either be refunded or collected through future
non-bypassable charges. This final reconciliation allows alternative methods of
third party valuation of the fair market value of these assets, including
outright sale, stock valuations and asset exchanges. Because generally accepted
accounting principles require the Company to estimate fair market values on a
plant-by-plant basis in advance of the final reconciliation, the financial
impacts of the Legislation with respect to stranded costs are subject to
material changes. Factors affecting such change may include estimation risk,
uncertainty of future energy 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 deferred debits created
from discontinuance of SFAS No. 71 pursuant to the Legislation no longer
probable, the Company will write off the corresponding balance of such assets as
a non-cash charge against earnings. One of the results of discontinuing the
application of SFAS No. 71 for the generation operations is the elimination of
the regulatory accounting effects of excess deferred income taxes and investment
tax credits related to such operations. The Company believes it is probable that
some parties will seek to return such amounts to ratepayers and accordingly, the
Company has recorded an offsetting liability.
Following are the classes of electric property, plant and equipment at
cost, with associated accumulated depreciation at December 31, 1999 (including
the impairment loss discussed above) and December 31, 1998.
Transmission General Consolidated Electric
Generation and Distribution and Intangible Plant in Service
------------ ---------------- -------------- ---------------------
(Millions of Dollars)
December 31, 1999:
Original cost .................................. $ 11,202 $ 4,531 $ 992 $ 16,725
Accumulated depreciation ....................... 4,767 1,263 251 6,281
------------ ------------ ------------ ------------
Property, plant and equipment - net(1) ......... $ 6,435 $ 3,268 741 10,444
============ ============ ============ ============
December 31, 1998:
Original cost .................................. $ 8,843 $ 4,196 $ 902 $ 13,941
Accumulated depreciation ....................... 3,822 1,276 207 5,305
------------ ------------ ------------ ------------
Property, plant and equipment - net(1) ......... $ 5,021 $ 2,920 $ 695 $ 8,636
============ ============ ============ ============
- ------------------------
(1) Includes non-rate regulated domestic and international generation
facilities of $696 million and $338 million at December 31, 1999 and 1998,
respectively, and international distribution facilities of $32 million and
$19 million at December 31, 1999 and 1998, respectively. Also, includes
property, plant and equipment of UNA of $1.8 billion at December 31, 1999.
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arose when long term debt was [ILLEGIBLE] issued, these costs were amortized
over the remaining original life of the retired debt. Effective July 1, 1999,
costs resulting from the retirement of debt attributable to the [ILLEGIBLE] HL&P
will be recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt," unless such costs will be recovered through regulated
cash flows. In that case, these costs will be deferred and recorded as a
regulatory asset by the entity through which the source of the regulated cash
flows will be derived. During the third and fourth quarters of 1999, the
generation portion of Reliant Energy HL&P incurred $11 million of losses from
extinguishment of debt which Reliant Energy HL&P's transmission and distribution
operations have recorded as a regulatory asset. This regulatory asset will be
amortized along with recoverable impaired plant costs as the assets are
recovered pursuant to the Legislation.
o (4) TRANSITION PLAN
In June 1998, the Texas Utility Commission issued an order in Docket No.
18465 approving the Company's Transition Plan filed by Electric Operations in
December 1997. The Transition Plan included base rate credits to residential
customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose
monthly billing is 1,000 kva or less are entitled to receive base rate credits
of 2% in each of 1998 and 1999. The Company implemented the Transition Plan
effective January 1, 1998. For additional information regarding the Transition
Plan, see Note 1(g).
Review of the Texas Utility Commission's order in Docket No. 18465 is
currently pending before the Travis County District Court. In August 1998, the
Office of the Attorney General for the State of Texas and a Texas municipality
filed an appeal seeking, among other things, to reverse the portion of the Texas
Utility Commission's order relating to the redirection of depreciation expenses
under the Transition Plan. The Office of the Attorney General has withdrawn its
appeal, but the Texas municipality continues to maintain its appeal. Because of
the number of variables that can affect the ultimate resolution of an appeal of
Texas Utility Commission orders, the Company cannot predict the outcome of this
matter or the ultimate effect that adverse action by the courts could have on
the Company.
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o (5) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
The Company offers energy price risk management services primarily related
to natural gas, electricity, crude oil and refined products, weather, coal and
certain air emissions regulatory credits. The Company provides these services by
utilizing a variety of derivative financial instruments, including fixed and
variable-priced physical forward contracts, fixed and variable-priced swap
agreements and options traded in the over-the-counter financial markets and
exchange-traded energy futures and option contracts (Trading Derivatives).
Fixed-price swap agreements require payments to, or receipts of payments from,
counterparties based on the differential between a fixed and variable price for
the commodity. Variable-price swap agreements require payments to, or receipts
of payments from, counterparties based on the differential between industry
pricing publications or exchange quotations.
Prior to 1998, the Company applied hedge accounting to certain physical
commodity activities that qualified for hedge accounting. In 1998, the Company
adopted mark-to-market accounting for all of its price risk management and
trading activities. Accordingly, since 1998, such Trading Derivatives are
recorded at fair value with realized and unrealized gains (losses) recorded as a
component of revenues. The recognized, unrealized balance is included in price
risk management assets/liabilities (See Note 1(o)).
The notional quantities, maximum terms and the estimated fair value of
Trading Derivatives at December 31, 1999 and 1998 are presented below (volumes
in billions of British thermal units equivalent (Bbtue) and dollars in
millions):
VOLUME-FIXED
VOLUME-FIXED PRICE MAXIMUM
1999 PRICE PAYOR RECEIVER TERM (YEARS)
---- ------------ ------------ ------------
Natural gas .................................................... 936,716 939,416 9
Electricity .................................................... 251,592 248,176 10
Crude oil and refined products ................................. 143,857 144,554 3
1998
----
Natural gas .................................................... 937,264 977,293 9
Electricity .................................................... 122,950 124,878 3
Crude oil and refined products ................................. 205,499 204,223 3
FAIR VALUE AVERAGE FAIR VALUE(A)
------------------------------ ------------------------------
1999 ASSET LIABILITIES ASSETS LIABILITIES
- ---- ------------ ------------ ------------ ------------
Natural gas ............................ $ 319 $ 299 $ 302 $ 283
Electricity ............................ 131 98 103 80
Crude oil and refined products ......... 134 145 127 132
------------ ------------ ------------ ------------
$ 584 $ 542 $ 532 $ 495
============ ============ ============ ============
1998
- ----
Natural gas ............................ $ 224 $ 212 $ 124 $ 108
Electricity ............................ 34 33 186 186
Crude oil and refined products ......... 29 23 21 17
------------ ------------ ------------ ------------
$ 287 $ 268 $ 331 $ 311
============ ============ ============ ============
- -------------------
(a) Computed using the ending balance of each quarter.
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In addition to the fixed-price notional volumes above, the Company also has
variable-priced agreements, as discussed above, totaling 3,797,824 and 1,702,977
Bbtue as of December 31, 1999 and 1998, respectively. Notional amounts reflect
the volume of transactions but do not represent the amounts exchanged by the
parties to the financial instruments. Accordingly, notional amounts do not
accurately measure the Company's exposure to market or credit risks.
All of the fair values shown in the tables above at December 31, 1999 and
1998 have been recognized in income. The fair value as of December 31, 1999 and
1998 was estimated using quoted prices where available and considering the
liquidity of the market for the Trading Derivatives. The prices and fair values
are subject to significant changes based on changing market conditions.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein are not
indicative of likely future cash flows, as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and the Company's risk management portfolio needs
and strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. The following table shows the composition of the total
price risk management assets of the Company as of December 31, 1999 and 1998.
December 31, 1999 December 31, 1998
--------------------------- --------------------------
Investment Investment
Grade (1) Total Grade (1) Total
---------- ---------- ---------- ----------
(Millions of Dollars)
Energy marketers ......................... $ 172 183 $ 103 $ 124
Financial institutions ................... 119 119 62 62
Gas and electric utilities ............... 184 186 47 48
Oil and gas producers .................... 6 30 7 8
Industrials .............................. 4 5 2 3
Independent power producers .............. 4 6 1 1
Others ................................... 64 67 45 47
---------- ---------- ---------- ----------
Total ............................ $ 553 $ 596 $ 267 $ 293
========== ==========
Credit and other reserves ................ (12) (6)
---------- ----------
Energy price risk management assets (2) .. $ 584 $ 287
========== ==========
(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (e.g., parent
company guarantees) and collateral, which encompass cash and standby
letters of credit.
(2) As of December 31, 1999, the Company had no credit risk exposure to any
single counterparty that represents greater than 5% of price risk
management assets.
(b) Non-Trading Activities.
To reduce the risk from market fluctuations in the revenues derived from
electric power, natural gas and related transportation, the Company enters into
futures transactions, swaps and options (Energy Derivatives) in order to hedge
certain natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas and electric power (a portion of which are firm
commitments at the inception of the hedge). Energy Derivatives are
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also utilized to fix the price of compressor fuel or other future operational
gas requirements and to protect natural gas distribution earnings against
unseasonably warm weather during peak gas heating months, although usage to
date for this purpose has not been material. The Company applies hedge
accounting with respect to its derivative financial instruments utilized in
non-trading activities.
The Company utilizes interest-rate derivatives (principally interest-rate
swaps) in order to adjust the portion of its overall borrowings which are
subject to interest rate risk and also utilizes such derivatives to effectively
fix the interest rate on debt expected to be issued for refunding purposes. In
addition, in 1999, the Company entered into foreign currency swaps to hedge a
portion of its investment in UNA.
For transactions involving either Energy Derivatives or interest-rate and
foreign currency derivatives, hedge accounting is applied only if the derivative
(i) reduces the risk of the underlying hedged item and (ii) is designated as a
hedge at its inception. Additionally, the derivatives must be expected to result
in financial impacts which 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.
In the case of interest-rate swaps associated with existing obligations,
cash flows and expenses associated with the interest-rate derivative
transactions are matched with the cash flows and interest expense of the
obligation being hedged, resulting in an adjustment to the effective interest
rate. When interest rate swaps are utilized to effectively fix the interest
rate for an anticipated debt issuance, changes in the market value of the
interest-rate derivatives are deferred and recognized as an adjustment to the
effective interest rate on the newly issued debt.
In the case of the foreign currency swaps which hedge a portion of the
Company's investment in UNA, income or loss associated with the foreign currency
derivative transactions is recorded as foreign currency translation adjustments
as a component of stockholders' equity. Such amounts generally offset amounts
recorded in stockholders' equity as adjustments resulting from translation of
the hedged investment into U.S. dollars.
Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in the Company's Statements of Consolidated
Income until the underlying hedged transaction occurs. Once it becomes probable
that an anticipated transaction will not occur, deferred gains and losses are
recognized. In general, the financial impact of transactions involving these
Energy Derivatives is included in the Company's Statements of Consolidated
Income under the captions (i) fuel expenses, in the case of natural gas
transactions and (ii) purchased power, in the case of electric power
transactions. Cash flows resulting from these transactions in Energy Derivatives
are included in the Company's Statements of Consolidated Cash Flows in the same
category as the item being hedged.
At December 31, 1999, the Company was fixed-price payors and fixed-price
receivers in Energy Derivatives covering 33,108 billion British thermal units
(Bbtu) and 5,481 Bbtu of natural gas, respectively. At December 31, 1998, the
Company was fixed-price payors and fixed-price receivers in Energy Derivatives
covering 42,498 Bbtu and 3,930 Bbtu of natural gas, respectively. Also, at
December 31, 1999 and 1998, the Company was a party to variable-priced Energy
Derivatives totaling 44,958 Bbtu and 21,437 Bbtu of natural gas, respectively.
The weighted average maturity of these instruments is less than one year.
The notional amount is intended to be indicative of the Company's level of
activity in such derivatives, although 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
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discussed below. Under such circumstances, gains (losses) are deferred and
recognized as a component of income when the underlying hedged item is
recognized in income.
The average maturity discussed above and the fair value discussed in Note
15 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions in the trading portfolio at any time in
response to changing market conditions, market liquidity and the Company's risk
management portfolio needs and strategies. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash receipts and
payments.
(c) Trading and Non-trading -- General Policy.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. While as yet the Company has experienced only minor losses due
to the credit risk associated with these arrangements, the Company has
off-balance sheet risk to the extent that the counterparties to these
transactions may fail to perform as required by the terms of each such contract.
In order to minimize this risk, the Company enters into such contracts primarily
with counterparties having a minimum Standard & Poor's or Moody's rating of BBB-
or Baa3, respectively. For long-term arrangements, the Company periodically
reviews the financial condition of such firms in addition to monitoring the
effectiveness of these financial contracts in achieving the Company's
objectives. Should the counterparties to these arrangements fail to perform, the
Company would seek to compel performance at law or otherwise obtain compensatory
damages in lieu thereof. The Company might be forced to acquire alternative
hedging arrangements or be required to honor the underlying commitment at then
current market prices. In such event, the Company might incur additional losses
to the extent of amounts, if any, already paid to the counterparties. In view of
its criteria for selecting counterparties, its process for monitoring the
financial strength of these counterparties and its experience to date in
successfully completing these transactions, the Company believes that the risk
of incurring a significant financial statement loss due to the non-performance
of counterparties to these transactions is minimal.
The Company's policies also prohibit the use of leveraged financial
instruments.
The Company has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading, marketing and risk
management activities. The committee's duties are to establish the Company's
commodity risk policies, allocate risk capital within limits established by the
Company's board of directors, approve trading of new products and commodities,
monitor risk positions and ensure compliance with the Company's risk management
policies and procedures and trading limits established by the Company's board of
directors.
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o (6) JOINTLY OWNED ELECTRIC UTILITY PLANT
(a) Investment in South Texas Project.
The Company has a 30.8% interest in the South Texas Project, which consists
of two 1,250 megawatt (MW) nuclear generating units and bears a corresponding
30.8% share of capital and operating costs associated with the project. As of
December 31, 1999, the Company's investment in the South Texas Project was $382
million (net of $2.1 billion accumulated depreciation which includes an
impairment loss recorded in 1999 of $745 million). For additional information
regarding the impairment loss, see Note 3. The Company's investment in nuclear
fuel was $44 million (net of $251 million amortization) as of such date.
The South Texas Project is owned as a tenancy in common among its four
co-owners, with each owner retaining its undivided ownership interest in the two
nuclear-fueled generating units and the electrical output from those units. The
four co-owners have delegated management and operating responsibility for the
South Texas Project to the South Texas Project Nuclear Operating Company
(STPNOC). STPNOC is managed by a board of
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directors comprised of one director from each of the four owners, along with the
chief executive officer of STPNOC. The four owners provide oversight through an
owners' committee comprised of representatives of each of the owners and through
the board of directors of STPNOC. Prior to November 1997, the Company was the
operator of the South Texas Project.
(b) Nuclear Insurance.
The Company and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
This coverage consists of $500 million in primary property damage insurance and
excess property insurance in the amount of $2.25 billion. With respect to excess
property insurance, the Company and the other owners of the South Texas Project
are subject to assessments, the maximum aggregate assessment under current
policies being $17 million during any one policy year. The application of the
proceeds of such property insurance is subject to the priorities established by
the Nuclear Regulatory Commission (NRC) regulations relating to the safety of
licensed reactors and decontamination operations.
Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $8.9 billion as of December 31, 1999. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations by maintaining the maximum amount of
financial protection available from private sources and by maintaining secondary
financial protection through an industry retrospective rating plan. The
assessment of deferred premiums provided by the plan for each nuclear incident
is up to $84 million per reactor, subject to indexing for inflation, a possible
5% surcharge (but no more than $10 million per reactor per incident in any one
year) and a 3% state premium tax. The Company and the other owners of the South
Texas Project currently maintain the required nuclear liability insurance and
participate in the industry retrospective rating plan.
There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.
(c) Nuclear Decommissioning.
The Company contributes $14.8 million per year to a trust established to
fund its share of the decommissioning costs for the South Texas Project. For a
discussion of the accounting treatment for the securities held in the Company's
nuclear decommissioning trust, see Note 1(l). In July 1999, an outside
consultant estimated the Company's portion of decommissioning costs to be
approximately $363 million. The consultant's calculation of decommissioning
costs for financial planning purposes used the DECON methodology (prompt
removal/dismantling), one of the three alternatives acceptable to the NRC and
assumed deactivation of Units Nos. 1 and 2 upon the expiration of their 40-year
operating licenses. While the current and projected funding levels currently
exceed minimum NRC requirements, no assurance can be given that the amounts held
in trust will be adequate to cover the actual decommissioning costs of the South
Texas Project. Such costs may vary because of changes in the assumed date of
decommissioning and changes in regulatory requirements, technology and costs of
labor, materials and equipment. Pursuant to the Legislation, costs associated
with nuclear decommissioning that have not been recovered as of January 1, 2002,
will continue to be subject to cost-of-service rate regulation and will be
included in a non-bypassable charge to transmission and distribution customers.
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o (7) EQUITY INVESTMENTS AND ADVANCES TO UNCONSOLIDATED SUBSIDIARIES
The Company accounts for investments in unconsolidated subsidiaries under
the equity method of accounting where (i) the ownership interest in the
affiliate ranges from 20% to 50%, (ii) the ownership interest is less than 20%
but the Company exercises significant influence over operating and financial
policies of such affiliate or (iii) the interest in the affiliate exceeds 50%
but the Company does not exercise control over the affiliate.
The Company's equity investments and advances in unconsolidated
subsidiaries at December 31, 1999 and 1998 were $1 billion and $1.1 billion,
respectively. The Company's equity loss from these investments, was $14 million
in 1999. For 1998 and 1997, the Company's equity income from these investments
was $71 million and $49 million, respectively. Dividends received from these
investments amounted to $14 million, $44 million and $46 million in 1999, 1998,
and 1997, respectively.
(a) Reliant Energy Latin America.
Reliant Energy is evaluating the sale of the Company's Latin American
assets in order to pursue business opportunities that are in line with its
strategies for the U.S. and Western Europe.
As of December 31, 1999, Reliant Energy Latin America indirectly holds
interests in Light Servicos de Electricidade S.A. (Light) (11.78%) which
transmits and distributes electricity in Rio De Janeiro, Brazil and holds 77.81%
of the common stock of Metropolitana Electricidade de Sao Paulo S.A.
(Metroplitana) which transmits and distributes electricity in Sao Paulo, Brazil;
three Columbian electric systems, Empresa de Energia del Pacifico S.A.E.S.P
(EPSA) (28.35%), Electricaribe (34.61%), and Electrocosta (35.17%); and three
electric systems in El Salvador (ranging from approximately 37% to 45%). In
addition, Reliant Energy Latin America indirectly holds interests in natural gas
systems in Columbia and a power generation plant in India.
As of December 31, 1999 and 1998, Light and Metropolitana had total
borrowings of $2.29 billion and $3.2 billion denominated in non-local
currencies. During the first quarter of 1999, the Brazilian real was devalued
and allowed to float against other major currencies. The effects of devaluation
on the non-local currency denominated borrowings caused the Company to record,
as a component of its equity earnings, an after-tax charge for the year ended
December 31, 1999 of $102 million as a result of foreign currency transaction
losses recorded by both Light and Metropolitana. At December 31, 1999 and 1998,
one U.S. dollar could be exchanged for 1.79 Brazilian real and 1.21 Brazilian
real, respectively. Because the Company uses the Brazilian real as the
functional currency to report Light's equity earnings, any decrease in the value
of the Brazilian real below its December 31, 1999 level will increase Light's
liability represented by the non-local currency denominated borrowings. This
amount will also be reflected in the Company's consolidated earnings, to the
extent of the Company's ownership interest in Light. Similarly, any increase in
the value of the Brazilian real above its December 31, 1999 level will decrease
Light's liability represented by such borrowings.
In April 1998, Light purchased 74.88% of the common stock of Metropolitana.
The purchase price for the shares was approximately $1.8 billion and was
financed with proceeds from bank borrowings. In August 1998, Reliant Energy
Latin America and another unrelated entity jointly acquired, through
subsidiaries, 65% of the stock of two Colombian electric distribution companies,
Electricaribe and Electrocosta, for approximately $522 million. The shares of
these companies are indirectly held by an offshore holding company jointly owned
by the Company and the other entity. In addition, in 1998, the Company acquired,
for approximately $150 million, equity interests in three electric distribution
systems located in El Salvador.
In June 1997, a consortium of investors which included Reliant Energy Latin
America acquired for $496 million a 56.7% controlling ownership interest in
EPSA. Reliant Energy Latin America contributed $152 million of the purchase
price for a 28.35% ownership interest in EPSA.
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In May 1997, Reliant Energy Latin America increased its indirect ownership
interest in an Argentine electric utility from 48% to 63%. The purchase price of
the additional interest was $28 million. On June 30, 1998, Reliant Energy Latin
America sold its 63% ownership interest in this Argentine affiliate and certain
related assets for approximately $243 million, Reliant Energy Latin America
acquired its initial ownership interests in the electric utility in 1992. The
Company recorded an $80 million after-tax gain from this sale in the second
quarter of 1998.
(b) Wholesale Energy Domestic.
In April 1998, the Company formed a limited liability corporation to
construct and operate a 490 MW electric generation plant in Boulder City, Nevada
in which the Company retained a 50% interest. The plant is anticipated to be
operational in the second quarter of 2000. In October 1998, the Company entered
into a partnership to construct and operate a 100 MW cogeneration plant in
Orange, Texas in which its ownership interest is 50%. The plant began commercial
operation in December, 1999. As of December 31, 1999, the Company's net
investment in these projects is $78 million and its total projected net
investment is approximately $90 million.
(c) Combined Financial Statement Data of Equity Investees and Advances to
Unconsolidated Subsidiaries.
The following tables set forth certain summarized financial information of
the Company's unconsolidated affiliates as of December 31, 1999 and 1998 and for
the years then ended or periods from the respective affiliates' acquisition date
through December 31, 1999, 1998 and 1997, if shorter:
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1999 1998 1997
------------ ------------ ------------
(THOUSANDS OF DOLLARS)
Income Statement:
Revenues .................. $ 4,421,942 $ 2,449,335 $ 2,011,927
Operating expenses ........ 3,329,559 1,762,166 1,460,248
Net income ................ (310,667) 514,005 403,323
DECEMBER 31,
------------------------------
1999 1998
------------ ------------
(THOUSANDS OF DOLLARS)
Balance Sheet:
Current assets ................. $ 1,553,166 $ 1,841,856
Noncurrent assets .............. 10,379,306 13,643,747
Current liabilities ............ 2,714,621 4,074,603
Noncurrent liabilities ......... 4,440,985 6,284,821
Owners' equity ................. 4,776,866 5,126,180
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o (8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND TIME WARNER SECURITIES
(a) Original investment in Time Warner Securities.
On July 6, 1999, the Company converted its 11 million shares of Time
Warner Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million
shares of Time Warner common stock (TW Common). Prior to the conversion, the
Company's investment in the TW Preferred was accounted for under the cost method
at a value of $990 million in the Company's Consolidated Balance Sheets. The TW
Preferred was redeemable after July 6, 2000) had an aggregate liquidation
preference of $100 per share (plus accrued and unpaid dividends), was entitled
to annual dividends of $3.75 per share until July 6, 1999 and was convertible by
the Company. The Company recorded pre-tax dividend income with respect to the TW
Preferred of $20.6 million in 1999 prior to the conversion and $41.3 million in
both 1998 and 1997. Due to the conversion, the Company will no longer receive
the quarterly dividend of $10.3 million that was paid on the TW Preferred but
will receive dividends, if declared and paid, on its investments in TW Common.
Effective on the conversion date, the shares of TW Common were classified as
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trading securities under SFAS No. 115 and an unrealized gain was recorded in the
amount of $2.4 billion ($1.5 billion after tax) to reflect the cumulative
appreciation in the fair value of the Company's investment in Time Warner
securities.
(b) ACES.
In July 1997, in order to monetize a portion of the cash value of its
investment in TW Preferred, the Company issued 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES) having an original principal amount
of approximately $1.052 billion. The market value of ACES is indexed to the
market value of TW Common. In July 2000, the ACES will be mandatorily
exchangeable for, at the Company's option, either shares of TW Common at the
exchange rate set forth below or cash with an equal value. The current exchange
rate is as follows:
Market Price of TW Common Exchange Rate
------------------------- -------------
Below $22.96875 2.0 shares of TW Common
$22.96875 - $27.7922 Share equivalent of $45.9375
Above $27.7922 1.6528 shares of TW Common
Prior to maturity, the Company has the option of redeeming the ACES if (i)
changes in federal tax regulations require recognition of a taxable gain on the
Company's TW investment and (ii) the Company could defer such gain by redeeming
the ACES. The redemption price is 105% of the closing sales price of the ACES as
determined over a period prior to the day redemption notice is given. The
redemption price may be paid in cash or in shares of TW Common or a combination
of the two.
By issuing the ACES, the Company effectively eliminated the economic
exposure of its investment in TW securities to decreases in the price of TW
Common below $22.96875. In addition, the Company retained 100% of any increase
in TW Common price up to $27.7922 per share and 17% of any increase in market
price above $27.7922.
Prior to the July 1999 conversion of the TW Preferred, any increase in the
market value of TW Common above $27.7922 was treated for accounting purposes as
an increase in the payment amount of the ACES equal to 83% of the increase in
the market price per share and was recorded by the Company as a non-cash
expense. As a result, the Company recorded in 1999 (prior to conversion), 1998
and 1997 a non-cash, unrealized accounting loss of $435 million, $1.2 billion
and $121 million, respectively (which resulted in an after-tax earnings
reduction of $283 million, or $0.99 per share, $764 million, or $2.69 per share,
and $79 million, or $0.31 per share, respectively). Following the conversion of
TW Preferred into TW Common, changes in the market value of the Company's TW
Common and the related offsetting changes in the liability related to the
Company's obligation under the ACES will be recorded in the Company's Statement
of Consolidated Income.
(c) ZENS.
On September 21, 1999, the Company issued approximately 17.2 million of its
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an
original principal amount of approximately $1.0 billion. At maturity the holders
of the ZENS will receive in cash the higher of the original principal amount of
the ZENS or an amount based on the then-current market value of TW Common, or
other securities distributed with respect to TW Common (one share of TW Common
and such other securities, if any, are referred to as reference shares). Each
ZENS has an original principal amount of $58.25 (the closing market price of the
TW Common on September 15, 1999) and is exchangeable at any time at the option
of the holder for cash equal to 95% (100% in certain cases) of the market value
of the reference shares attributable to one ZENS. The Company pays interest on
each ZENS at an annual rate of 2% plus the amount of any quarterly cash
dividends paid in respect of the quarterly interest period on the reference
shares attributable to each ZENS. Subject to certain conditions, the Company has
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the right to defer interest payments from time to time on the ZENS for up to 20
consecutive quarterly periods. As of December 31, 1999, no interest Payments on
the ZENS had been deferred.
Of the $980 million net proceeds from the Offering, the Company used $443
million for general corporate purposes, including repayment of Company
indebtedness. The Company used $537 million of the net proceeds to purchase 9.2
million shares of TW Common, which are classified as trading securities under
SFAS No. 115. Unrealized gains and losses resulting from changes in the market
value of the TW Common are recorded in the Company's Statements of Consolidated
Income.
An increase above $58.25 (subject to certain adjustments) in the market
value per share of TW Common results in an increase in the Company's liability
for the ZENS and is recorded by the Company as a non-cash expense. If the market
value per share of TW Common declines below $58.25 (subject to certain
adjustments), the liability for the ZENS would not decline below the original
principal amount. However, the decline in market value of the Company's
investment in the TW Common would be recorded as an unrealized loss as discussed
above.
Prior to the purchase of additional shares of TW Common on September 21,
1999, the Company owned approximately 8 million shares of TW Common that were in
excess of the 38 million shares needed to economically hedge its ACES
obligation. For the period from July 6, 1999 to the ZENS issuance date, losses
(due to the decline in the market value of the TW Common during such period) on
these 8 million shares were $122 million ($79 million after tax). The 8 million
shares of TW Common combined with the additional 9.2 million shares purchased
are expected to be held to facilitate the Company's ability to meet its
obligation under the ZENS.
The following table sets forth certain summarized financial information of
the Company's investment in TW securities and the Company's ACES and ZENS
obligations.
TW Investment ACES ZENS
------------ ------------ ------------
(THOUSANDS OF DOLLARS)
Balance at January 1, 1997 .................. $ 990,000
Issuance of indexed debt securities ......... $ 1,052,384
Loss on indexed debt securities ............. 121,402
------------ ------------
Balance at December 31, 1997 ................ 990,000 1,173,786
Loss on indexed debt securities ............. 1,176,211
------------ ------------
Balance at December 31, 1998 ................ 990,000 2,349,997
Issuance of indexed debt securities ......... $ 1,000,000
Purchase of TW Common ....................... 537,055
Loss on indexed debt securities ............. 388,107 241,416
Gain on TW Common ........................... 2,452,406
------------ ------------ ------------
Balance at December 31, 1999 ................ $ 3,979,461 $ 2,738,104 $ 1,241,416
============ ============ ============
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o (14) COMMITMENTS AND CONTINGENCIES
(a) Commitments.
The Company has various commitments for capital expenditures, fuel,
purchased power and operating leases. Commitments in connection with Electric
Operations' capital program are generally revocable by the Company, subject to
reimbursement to manufacturers for expenditures incurred or other cancellation
penalties, Wholesale Energy has entered into commitments associated with various
non-rate regulated generating projects aggregating S324 million along with
various generating equipment purchases aggregating $318 million for delivery
from 2000 to 2001 that are anticipated to be used for future development
projects. The Company's other commitments have various quantity requirements and
durations. However, if these requirements could not be met, various alternatives
are available to mitigate the cost associated with the contracts' commitments.
(b) Fuel and Purchased Power.
Reliant Energy HL&P is a party to several long-term coal, lignite and
natural gas contracts which have various quantity requirements and durations.
Minimum payment obligations for coal and transportation agreements that extend
through 2011 are approximately $187 million in 2000, $188 million in 2001 and
$188 million in 2002. Purchase commitments related to lignite mining and lease
agreements, natural gas purchases and storage contracts, and purchased power are
not material to the operations of the Company,
Currently Reliant Energy HL&P is allowed recovery of these costs through
base rates for electric service. As of December 31, 1999, certain of these
contracts are above market. The Company anticipates that stranded cost
associated with these obligations will be recoverable through the stranded cost
recovery mechanisms contained in the Legislation. For information regarding the
Legislation, see Note 3.
(c) Operations Agreement with City of San Antonio.
As part of the 1996 settlement of certain litigation claims asserted by the
City of San Antonio with respect to the South Texas Project, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in order to take advantage of each system's lower cost
resources. Under the terms of the joint operations agreement entered into
between CPS and Electric Operations, the Company has guaranteed CPS minimum
annual savings of $10 million and a minimum cumulative savings of $150 million
over the 10-year term of the agreement. Based on current forecasts and other
assumptions regarding
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the combined operation of the two generating systems, the Company anticipates
that the savings resulting from joint operations will equal or exceed the
minimum savings guaranteed under the joint operating agreement. In 1999, 1998
and 1997, savings generated for CPS' account were approximately $14 million, $14
million and S22 million, respectively. Through December 31, 1999, cumulative
earnings generated for CPS' account were approximately $64 million.
(d) Transportation Agreement.
Resources had an agreement (ANR Agreement) with ANR Pipeline Company (ANR)
which contemplated that Resources would transfer to ANR an interest in certain
of Resources' pipeline and related assets. The interest represented capacity of
250 Mmcf/day. Under the ANR Agreement, an ANR affiliate advanced $125 million to
Resources. Subsequently, the parties restructured the ANR Agreement and
Resources refunded in 1995 and 1993, $50 million and $34 million, respectively,
to ANR. Resources recorded $41 million as a liability reflecting ANR's use of
130 Mmcf/day of capacity in certain of Resources' transportation facilities. The
level of transportation will decline to 100 Mmcf/day in the year 2003 with a
refund of $5 million to ANR. The ANR Agreement will terminate in 2005 with a
refund of the remaining balance.
(e) Lease Commitments.
The following table sets forth certain information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31, 1999
which primarily relate to Resources principally consisting of rental agreements
for building space, data processing equipment and vehicles, including major work
equipment (in millions):
2000 .......................... $ 16
2001 .......................... 15
2002 .......................... 10
2003 .......................... 8
2004 .......................... 7
2005 and beyond ............... 25
----
Total .................... $ 81
====
(f) Letters of Credit.
At December 31, 1999, the Company had letters of credit totaling
approximately $14 million under which it is obligated to reimburse drawings, if
any.
(g) Cross Border Leases.
During the period from 1994 through 1997, under cross border lease
transactions, UNA leased several of its power plants and related equipment and
turbines to non-Netherlands based investors and concurrently leased the
facilities back under sublease arrangements with remaining terms as of December
31, 1999 of two to 25 years. Such transactions involve the Company providing to
a foreign investor an ownership right in (but not necessarily title to) an
asset, with a leaseback of the asset. The net proceeds to UNA of the
transactions are being amortized to income over the lease terms. At December 31,
1999, the deferred gain on these transactions totaled $87 million assuming an
exchange rate of 2.19 NLG per U.S. dollar (the exchange rate on December 31,
1999). UNA utilized proceeds from the head lease transactions to prepay sublease
obligations as well as provide a source for payment of end of term purchase
options and other financial undertakings. The leased property remains on the
financial statements of UNA and continues to be depreciated. In the case of
early termination of the cross border leases, UNA would be contingently liable
for certain payments to the sublessors, which at December 31, 1999 are estimated
to be $254 million. Prior to March 1, 2000, UNA will be required by some of the
lease agreements to obtain standby letters of credit in favor of the sublessors
in the event of early termination in the amount of $205 million (assumes an
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exchange rate of 2.19 NLG per U.S. dollar, the exchange rate on December 31,
1999). Commitments for such letters of credit have been obtained as of December
31, 1999.
(h) Environmental Matters.
The Company is a defendant in litigation arising out of the environmental
remediation of a site in Corpus Christi, Texas. The litigation was instituted in
1985 by adjacent landowners. The litigation is pending before the United States
District Court for the Southern District of Texas, Corpus Christi Division. The
site was operated by third parties as a metals reclaiming operation. Although
the Company neither operated nor owned the site, certain transformers and other
equipment originally sold by the Company may have been delivered to the site by
third parties. The Company and others have remediated the site pursuant to a
plan approved by appropriate state agencies and a federal court. To date, the
Company has recovered or has commitments to recover from other responsible
parties $2.2 million of the more than $3 million it has spent on remediation.
In 1992, the United States Environmental Protection Agency (EPA) (i)
identified the Company, along with several other parties, as "potentially
responsible parties" (PRP) under the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) for the costs of cleaning up a site
located adjacent to one of the Company's transmission lines in La Marque, Texas
and (ii) issued an administrative order for the remediation of the site. The
Company believes that the EPA took this action solely on the basis of
information indicating that the Company in the 1950s acquired record title to a
portion of the land on which the site is located. The Company does not believe
that it now or previously has held any ownership interest in the property
covered by the order and has obtained a judgment to that effect from a court in
Galveston County, Texas. Based on this judgment and other defenses that the
Company believes to be meritorious, the Company has elected not to adhere to the
EPA's administrative order, even though the Company understands that other PRPs
are proceeding with site remediation. To date, neither the EPA nor any other PRP
has instituted an action against the Company for any share of the remediation
costs for the site. However, if the Company was determined to be a responsible
party, the Company could be jointly and severally liable along with the other
PRPs for the aggregate remediation costs of the site (which the Company
currently estimates to be approximately $80 million in the aggregate) and could
be assessed substantial fines and damage claims. Although the ultimate outcome
of this matter cannot currently be predicted at this time, the Company does not
believe that this matter will have a material adverse effect on the Company's
financial condition, or results of operations or cash flows.
From time to time the Company has received notices from regulatory
authorities or others regarding its status as a PRP in connection with sites
found to require remediation due to the presence of environmental contaminants.
In addition, the Company has been named as defendant in litigation related to
such sites and in recent years has been named, along with numerous others, as a
defendant in several lawsuits filed by a large number of individuals who claim
injury due to exposure to asbestos while working at sites along the Texas Gulf
Coast. Most of these claimants have been workers who participated in
construction of various industrial facilities, including power plants, and some
of the claimants have worked at locations owned by the Company. The Company
anticipates that additional claims like those received may be asserted in the
future and intends to continue vigorously contesting claims which it does not
consider to have merit. Although their ultimate outcome cannot be predicted at
this time, the Company does not believe, based on its experience to date, that
these matters, either individually or in the aggregate, will have a material
adverse effect on the Company's financial position, results of operations or
cash flows.
(i) Other.
The Company is involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions, and governmental agencies regarding
matters arising in the ordinary course of business, some of which involve
substantial amounts. The Company's management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. The Company's management believes that
the effect on the Company's respective financial statements, if any, from the
disposition of these matters will not be material.
In February 1996, the cities of Wharton, Galveston and Pasadena filed suit,
for themselves and a proposed class of all similarly situated cities in Reliant
Energy HL&P's service area, against the Company and Houston Industries Finance
Inc. (formerly a wholly owned subsidiary of the Company) alleging underpayment
of municipal franchise fees. Plaintiffs in essence claim that they are entitled
to 4% of all receipts of any kind for business conducted within city limits or
with use of city rights-of-way. Plaintiffs advance their claims notwithstanding
their failure to assert such claims over the previous four decades. Because all
of the franchise ordinances affecting Electric Operations expressly impose fees
only on the Company's own receipts and only from sales of electricity for
consumption within a city, the Company regards plaintiffs' allegations as
spurious and is vigorously contesting the case. The plaintiffs' pleadings assert
that their damages exceed $250 million. The 269th Judicial District Court for
Harris County has granted a partial summary judgment in favor of the Company
dismissing all claims for franchise fees based on sales tax collections. Other
motions for partial summary judgment were denied. A jury trial of the remaining
individual claims of the three named cities (but not the entire class) began on
February 14, 2000 and is expected to conclude by the end of March 2000. The
extent to which issues resolved in this trial may affect the claims of the other
class member cities cannot be determined until final judgment is rendered. The
Company believes that it is very unlikely that resolution of this case will have
a material adverse effect on the Company's financial condition, results of
operations or cash flows.
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