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EXHIBIT 99.a
RELIANT ENERGY RESOURCES CORP.
Items Incorporated by Reference
ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY AND RESOURCES FORM 10-K:
o Item 3. LEGAL PROCEEDINGS
(b) Resources Corp.
For a description of certain legal and regulatory proceedings affecting
Resources, see Note 8(d) to Resources' Consolidated Financial Statements, which
note is 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 7A QUANTITATIVE 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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<PAGE> 10
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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<PAGE> 11
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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<PAGE> 12
ITEMS INCORPORATED BY REFERENCE FROM THE RESOURCES 10-K NOTES:
o (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(c) Regulatory Assets and Regulation.
Resources applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of its Natural Gas Distribution operations and to MRT. Resources'
Natural Gas Distribution operations are subject to regulation at the state or
municipal level and the Interstate Pipelines operations of MRT are subject to
regulation by the Federal Energy Regulatory Commission. As of December 31, 1999
and 1998, Resources had recorded as deferred debits and other deferred credits
approximately $4 million and $12 million, respectively, of net regulatory
assets.
If, as a result of changes in regulation or competition, Resources'
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" and SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," Resources would be required to write off or write down such regulatory
assets and liabilities.
o (2) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
Resources 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. Resources 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, Resources applied hedge accounting to certain physical
commodity activities that qualified for hedge accounting. In 1998, Resources
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(q)).
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<PAGE> 13
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):
<TABLE>
<CAPTION>
VOLUME-FIXED VOLUME-FIXED MAXIMUM
PRICE PAYOR PRICE RECEIVER TERM (YEARS)
------------ -------------- ------------
1999
<S> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
AVERAGE FAIR
FAIR VALUE VALUE(a)
----------------------- ------------------------
ASSETS LIABILITIES ASSETS LIABILITIES
---------- ----------- ---------- -----------
1999
<S> <C> <C> <C> <C>
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
========== ========== ========== ==========
</TABLE>
---------------
(a) Computed using the ending balance of each quarter.
In addition to the fixed-price notional volumes above, Resources 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 Resources' exposure to market or credit risks.
All of the fair values shown in the tables above at December 31, 1999 and
December 31, 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 Resources' 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.
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<PAGE> 14
In addition to the risk associated with price movements, credit risk is
also inherent in Resources' 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 Resources as of December 31, 1999 and 1998.
<TABLE>
<CAPTION>
DECEMBER 31, 1999 DECEMBER 31, 1998
----------------------- -----------------------
INVESTMENT INVESTMENT
GRADE(1) TOTAL GRADE(1) TOTAL
---------- ---------- ---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
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
========== ==========
</TABLE>
----------
(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, Resources 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, Resources 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 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. Resources applies hedge accounting with
respect to its derivative financial instruments utilized in non-trading
activities.
For transactions involving Energy 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.
Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in Resources' 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 Resources' Statements of Consolidated Income
under the captions (i) fuel expenses, in the case of natural gas transactions
and (ii) purchased
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<PAGE> 15
power, in the case of electric power transactions. Cash flows resulting from
these transactions in Energy Derivatives are included in Resources' Statements
of Consolidated Cash Flows in the same category as the item being hedged.
At December 31, 1999, Resources 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,
Resources 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, Resources 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 Resources' 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 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
10 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 Resources' 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 Resources' risk management activities. Credit risk relates to
the risk of loss resulting from non-performance of contractual obligations by a
counterparty. While as yet Resources has experienced only minor losses due to
the credit risk associated with these arrangements, Resources 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, Resources 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, Resources periodically reviews the
financial condition of such firms in addition to monitoring the effectiveness of
these financial contracts in achieving Resources' objectives. Should the
counterparties to these arrangements fail to perform, Resources would seek to
compel performance at law or otherwise obtain compensatory damages in lieu
thereof. Resources might be forced to acquire alternative hedging arrangements
or be required to honor the underlying commitment at then-current market prices.
In such event, Resources 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, Resources believes that the risk of incurring a significant
financial statement loss due to the non-performance of counterparties to these
transactions is minimal.
Reliant Energy's policies prohibit the use of leveraged financial
instruments.
Reliant Energy has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including Resources' trading, marketing and risk
management activities. The Committee's duties are to establish Reliant Energy's
and Resources' commodity risk policies, allocate risk capital within limits
established by Reliant Energy's board of directors, approve trading of new
products and commodities, monitor risk positions and ensure compliance with
Reliant Energy's risk management policies and procedures and trading limits
established by Reliant Energy's board of directors.
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<PAGE> 16
o (8) COMMITMENTS AND CONTINGENCIES
(a) Lease Commitments.
The following table sets forth certain information concerning
Resources' obligations under non-cancelable long-term operating leases
principally consisting of rental agreements for building space and data
processing equipment and vehicles, including major work equipment (in millions):
<TABLE>
<S> <C>
2000 .............................................. $ 15
2001 .............................................. 14
2002 .............................................. 9
2003 .............................................. 8
2004 .............................................. 6
2005 and beyond ................................... 18
-------
Total ............................................. $ 70
=======
</TABLE>
Resources has a master leasing agreement which provides for the lease of
vehicles, construction equipment, office furniture, data processing equipment
and other property. For accounting purposes, the lease is treated as an
operating lease. At December 31, 1999, the unamortized value of equipment
covered by the master leasing agreement was $17 million. Resources does not
expect to lease additional property under this lease agreement.
Total rental expense for all was $33 million, $25 million and $24
million in 1999, 1998 and 1997, respectively.
(b) Indemnity Provisions.
At December 31, 1999 and 1998, Resources had a $0.5 million and $5.8
million, accounting reserve on its Consolidated Balance Sheets in other deferred
credits for possible indemnity claims asserted in connection with its
disposition of Resources' former subsidiaries or divisions, including the sale
of (i) Louisiana Intrastate Gas Corporation, a former Resources subsidiary
engaged in the intrastate pipeline and liquids extraction business; (ii) Arkla
Exploration Company, a former Resources subsidiary engaged in oil and gas
exploration and production activities; and (iii) Dyco Petroleum Company, a
former Resources subsidiary engaged in oil and gas exploration and production.
(c) 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 restructed the ANR
Agreement and Resources refunded in 1995 and 1993, respectively, $50 million and
$34 million to ANR or an affiliate. Resources recorded $41 million as a
liability reflecting ANR's or its affiliates' 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 refund of $5 million to an
ANR affiliate. The ANR Agreement will terminate in 2005 with a refund of the
remaining balance.
(d) Environmental Matters.
To the extent that potential environmental remediation costs are
quantified within a range, Resources establishes reserves equal to the most
likely level of costs within the range and adjusts such accruals as better
information becomes available. In determining the amount of the liability,
future costs are not discounted to their present value and the liability is not
offset by expected insurance recoveries. If justified by circumstances within
Resources' business subject to SFAS No. 71, corresponding regulatory assets are
recorded in anticipation of recovery through the rate making process.
Manufactured Gas Plant Sites. Resources and its predecessors operated a
manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works (FMGW) until 1960. Resources has
substantially completed remediation of the main site other than ongoing water
monitoring and treatment. The manufactured gas was stored in separate holders.
Resources is negotiating clean-up of one such holder. There are six other former
MGP sites in the Minnesota service territory. Remediation has been completed on
one site. Of the remaining five sites, Resources believes that two were neither
owned nor operated by Resources; two were owned by Resources at one time but
were operated by others and currently owned by others; and one site was
previously owned and operated by Resources but is currently owned by others.
Resources believes it has no liability with respect to the sites it neither
owned nor operated.
At December 31, 1999 and 1998, Resources had accrued $18.8 million and
$15.2 million, respectively, for remediation of the Minnesota sites. At December
31, 1999, the estimated range of possible remediation costs was $10 million to
$49 million. The low end of the range was determined based on only those sites
presently, owned or known to have been operated by Resources, assuming use of
Resources proposed remediation methods. The upper end of the range was
determined based on the sites once owned by Resources, whether or not operated
by
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<PAGE> 17
Resources. The cost estimate of the FMGW site are based on studies of that site.
The remediation costs for the other sites are based on industry average costs
for remediation of sites of similar size. The actual remediation costs will be
dependent upon the number of sites remediated, the participation of other
potentially responsible parties, if any, and the remediation methods used.
Other Minnesota Matters. At December 31, 1999 and 1998, Resources had
recorded accruals of $1.2 million and $5.4 million, respectively (with a maximum
estimated exposure of approximately $13 million and $8 million at December 31,
1999 and 1998, respectively), for other environmental matters for which
remediation may be required.
In its 1995 rate case, Reliant Energy Minnegasco was allowed to recover
approximately $7 million annually for remediation costs. In 1998, Reliant Energy
Minnegasco received approval to reduce its annual recovery rate to zero.
Remediation costs are subject to a true-up mechanism whereby any over or under
recovered amounts, net of certain insurance recoveries, plus carrying charges,
are deferred for recovery or refund in the next rate case. At December 31, 1999
and 1998, Reliant Energy Minnegasco had over recovered $13 million, including
insurance recoveries. At December 31, 1999 and 1998, Reliant Energy Minnegasco
had recorded a liability of $20.0 million and $20.6 million, respectively, to
cover the cost of future remediation. Reliant Energy Minnegasco expects that
approximately 40% of its accrual as of December 31, 1999 will be expended within
the next five years. The remainder will be expended on an ongoing basis for an
estimated 40 years. In accordance with the provisions of SFAS No. 71, a
regulatory asset has been recorded equal to the liability accrued. Resources
believes the difference between any cash expenditures for these costs and the
amount recovered in rates during any year will not be material to Resources'
financial position, results of operations or cash flows.
Issues relating to the identification and remediation of MGPs are
common in the natural gas distribution industry. Resources has received notices
from the United States Environmental Protection Agency (EPA) and others
regarding its status as a potentially responsible party (PRP) for other sites.
Based on current information, Resources has not been able to quantify a range of
environmental expenditures for potential remediation expenditures with respect
to other MGP sites.
Mercury Contamination. Like other natural gas pipelines, Resources'
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 Resources has conducted remediation at sites found to be
contaminated. Although Resources 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 by Resources and others in the natural
gas industry to date and on the current regulations regarding remediation of
such sites, Resources believes that the cost of any remediation of such sites
will not be material to Resources' financial position, results of operations or
cash flows.
Potentially Responsible Party Notifications. From time to time Resources
has received notices from regulatory authorities or others regarding its status
as a PRP in connection with sites found to require remediation due to the
presence of environmental contaminants. Considering the information currently
known about such sites and the involvement of Resources in activities at these
sites, Resources does not believe that these matters will have a material
adverse effect on Resources' financial position, results of operations or cash
flows.
Resources is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on Resources' Consolidated Financial Statements, if any, from
the disposition of these matters will not be material.
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