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EXHIBIT 99A
[ITEMS INCORPORATED BY REFERENCE FROM THE COMPANY 10-K, THE COMPANY
FIRST QUARTER 10-Q AND THE COMPANY SECOND QUARTER 10-Q.]
ITEM 3. LEGAL PROCEEDINGS.
(a) Company.
For a description of certain legal and regulatory proceedings affecting the
Company, see Notes 3(b), 12(h) and 12(i) to the Company's Consolidated Financial
Statements, which notes are incorporated herein by reference.
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 AND ITS SUBSIDIARIES
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) the future growth in the Company's and its subsidiaries' energy
sales; (ii) weather; (iii) the success of the Company's and its subsidiaries'
entry into non-rate regulated businesses such as energy marketing and
international and domestic power projects; (iv) the Company's and its
subsidiaries' ability to respond to rapid changes in a competitive environment
and in the legislative and regulatory framework under which they have
traditionally operated; (v) rates of economic growth in the Company's and its
subsidiaries' service areas; (vi) the ability of the Company and its
subsidiaries to control costs and to maintain pricing structures that are both
attractive to customers and profitable; (vii) the outcome of future rate
proceedings; (viii) the effect that foreign exchange rate changes may have on
the Company's investments in international operations; and (ix) future
legislative initiatives.
In order to adapt to the increasingly competitive environment in which the
Company operates, 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 properties or currently
operating business units and new products, services and customer strategies. In
addition, the Company continues to engage in new business ventures, such as
electric power trading and marketing, which arise from competitive and
regulatory changes in the utility industry.
COMPETITION AND RESTRUCTURING OF THE 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.
Long-Term Trends in Electric Utility Industry. The electric utility
industry historically has been composed of vertically integrated companies
providing electric service on an exclusive basis within governmentally-defined
geographic areas. Prices for electric service have typically been set by
governmental authorities under principles designed to provide the utility with
an opportunity to recover its cost of providing electric service plus a
reasonable return on its invested capital. Federal legislation and regulation as
well as legislative and regulatory initiatives in various states have encouraged
competition among electric utility and non-utility owned power generators. These
developments, combined with increased demand for lower-priced electricity and
technological advances in electric generation, have continued to move the
electric utility industry in the direction of more competition.
Based on a strategic review of the Company's business and of ongoing
developments in the electric utility and related industries regarding
competition, regulation and consolidation, the Company's management believes
that the electric utility industry will continue its path toward competition,
albeit on a state-by-state basis. The Company's management also believes the
business of electricity and natural gas are converging and consolidating and
these trends will alter the structure and business practices of companies
serving these markets in the future.
Competition in Wholesale Market. The Federal Energy Policy Act of 1992, the
Public Utility Regulatory Act of 1995 (now the Texas Utilities Code) and
regulations promulgated by the Federal Energy Regulatory Commission (FERC)
contain provisions intended to facilitate the development of a wholesale energy
market. Although Reliant Energy HL&P's wholesale sales traditionally have
accounted for less than 1% of its total revenues, the expansion of competition
in the wholesale electric market is significant in that it has increased the
range of non-utility competitors, such as exempt wholesale generators (EWGs) and
power marketers, in the Texas electric market as well as resulted in fundamental
changes in the operation of the state transmission grid.
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. The ERCOT ISO, the first
in the nation, is a key component for implementing the Texas Utility
Commission's overall strategy to create a
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competitive wholesale market. ERCOT formed an ad hoc committee in early 1998 to
investigate the potential impacts of a competitive retail market on the ISO. The
ERCOT committee report was released in December 1998 and concluded that the
ISO's role and function would necessarily expand in a competitive retail
environment, but the changes required of the ISO to support retail choice should
not impede introduction of retail choice.
Competition in Retail Market. The Company estimates that, since 1978,
cogeneration projects representing approximately one-third of current total peak
generating capability have been built in the Houston area and that, as a result,
Reliant Energy HL&P has seen a reduction of approximately 2,500 MW in customer
load to self-generation. Reliant Energy HL&P has utilized flexible pricing to
respond to situations where large industrial customers have an alternative to
buying power from it, primarily by constructing their own generating facilities.
Under a tariff option approved by the Texas Utility Commission in 1995, Reliant
Energy HL&P was permitted to implement contracts based upon flexible pricing for
up to 700 MW. Currently, this rate is fully subscribed.
Texas law currently does not permit retail sales by unregulated entities
such as cogenerators. The Company anticipates that cogenerators and other
interests will continue to exert pressure to obtain access to the electric
transmission and distribution systems of regulated utilities for the purpose of
making retail sales to customers of regulated utilities.
Legislative Proposals. A number of proposals to restructure the electric
utility industry have been introduced in the 1999 session of the Texas
legislature. If adopted, legislation may permit and encourage alternative
suppliers to compete to serve Reliant Energy HL&P's current rate-regulated
retail customers. The various legislative proposals include provisions governing
recovery of stranded costs and permitting securitization of those costs;
freezing rates until 2002; requiring firm sales of energy to competing retail
electric providers; requiring disaggregation of generation, transmission and
distribution, and retail sales into separate companies and limiting the ability
of existing utilities' affiliates competing for retail electric customers on the
basis of price until they have lost a substantial percentage of their
residential and small commercial load to alternative retail providers. In
addition to the Texas legislative proposals, a number of federal legislative
proposals to promote retail electric competition or restructure the U.S.
electric utility industry have been introduced during the current congressional
session.
At this time, the Company is unable to make any prediction as to whether
any legislation to restructure electric operations or provide retail competition
will be enacted or as to the content or impact on the Company of any legislation
which may be enacted. However, because the proposed legislation is intended to
fundamentally restructure electric utility operations, it is likely that enacted
legislation would have a material impact on the Company.
Stranded Costs. As the U.S. electric utility industry continues its
transition to a more competitive environment, a substantial amount of fixed
costs previously approved for recovery under traditional utility regulatory
practices (including regulatory assets and liabilities) may become "stranded,"
i.e., unrecoverable at competitive market prices. The issue of stranded costs
could be particularly significant with respect to fixed costs incurred in
connection with the past construction of generation plants, such as nuclear
power plants, which, because of their high fixed costs, would not command the
same price for their output as they have in a regulated environment.
In January 1997, the Texas Utility Commission delivered a report to the
Texas legislature on stranded investments in the electric utility industry in
Texas (referred to by the Texas Utility Commission as "Excess Cost Over Market")
(ECOM). In April 1998, the Texas Utility Commission submitted to the Texas
Senate Interim Committee on Electric Utility Restructuring an updated study of
ECOM estimates. Assuming that retail competition is adopted at the beginning of
2002, the updated study estimated that the total amount of stranded costs for
all Texas electric utilities could be $4.5 billion. If instead, retail
competition is adopted one year later, the study estimates statewide ECOM to be
$3.3 billion. Estimates of ECOM vary widely and there is inherent uncertainty in
calculating these costs.
Transition Plan. In June 1998, the Texas Utility Commission approved the
Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition
Plan included base rate credits to residential and certain commercial
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customers in 1998 and 1999, an overall rate of return cap formula for 1998 and
1999 and approval of accounting procedures designed to accelerate recovery of
stranded costs which may arise under restructuring legislation. The Transition
Plan permits the redirection of depreciation expense to generation assets that
Electric Operations otherwise would apply to transmission, distribution and
general plant assets. In addition, the Transition Plan provides that all
earnings above a 9.844% overall annual rate of return on invested capital be
used to recover Electric Operations' investment in generation assets. In
1998, Reliant Energy HL&P recorded an additional $194 million in depreciation
under the Transition Plan. Certain parties have appealed the order approving the
Transition Plan. For additional information, see Notes 1(f) and 3(b) to the
Company's Consolidated Financial Statements.
COMPETITION -- OTHER OPERATIONs
Natural Gas Distribution competes primarily with alternate energy sources
such as electricity and other fuel sources as well as with providers of energy
conservation products. 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.
The Interstate Pipeline 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 Pipeline 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 Pipeline and the level of
competition for transport and storage services.
Reliant Energy Services competes for sales in its gas and power trading and
marketing business with other natural gas and power 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, natural gas suppliers and
natural gas 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.
Competition for acquisition of international and domestic non-rate
regulated power projects is intense. International and Power Generation compete
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 greater portfolios of projects. Competitive factors relevant to the
non-utility power industry include financial resources, access to non-recourse
funding and regulatory factors.
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.
ACCOUNTING TREATMENT OF ACES
The Company accounts for its investment in Time Warner Convertible
Preferred Stock (TW Preferred) under the cost method. As a result of the
Company's issuance of the ACES, a portion of the increase in the market value
above $27.7922 per share of Time Warner common stock (the security into which
the TW Preferred is convertible) (TW
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Common) results in unrealized accounting losses to the Company, pending the
conversion of the Company's TW Preferred into TW Common. For consistency
purposes, the TW Common and related per share prices retroactively reflect a 2
for 1 stock split effective December 15, 1998.
Prior to the conversion of the TW Preferred into TW Common, when the market
price of TW Common increases above $27.7922, the Company records in Other Income
(Expense) an unrealized, non-cash accounting loss for the ACES equal to the
aggregate amount of such increase as applicable to all ACES multiplied by
0.8264. In accordance with generally accepted accounting principles, this
accounting loss (which reflects the unrealized increase in the Company's
indebtedness with respect to the ACES) may not be offset by accounting
recognition of the increase in the market value of the TW Common that underlies
the TW Preferred. Upon conversion of the TW Preferred (which is anticipated to
occur in June 1999 when the preferential dividend on the TW Preferred expires),
the Company will begin recording future unrealized net changes in the market
prices of the TW Common and the ACES as a component of common stock equity and
other comprehensive income.
As of December 31, 1998, the market price of TW Common was $62.062 per
share. Accordingly, the Company recognized an increase of $1.2 billion in 1998
in the unrealized liability relating to its ACES indebtedness (which resulted in
an after-tax earnings reduction of $764 million or $2.69 basic earnings per
share in 1998). The Company believes that the cumulative unrealized loss for the
ACES of approximately $1.3 billion is more than economically offset by the
approximately $1.8 billion unrecorded unrealized gain at December 31, 1998
relating to the increase in the fair value of the TW Common underlying the
investment in TW Preferred since the date of its acquisition. Any gain related
to the increase in fair value of TW Common would be recognized as a component of
net income upon the sale of the TW Preferred or the shares of TW Common into
which such TW Preferred is converted. As of March 11, 1999, the price of TW
Common was $70.75 per share, which would have resulted in the Company
recognizing an additional increase of $329 million in the unrealized liability
represented by its indebtedness under the ACES. The related unrecorded
unrealized gain as of March 11, 1999 would have been computed as an additional
$398 million.
Excluding the unrealized, non-cash accounting loss for ACES, the Company's
retained earnings and total common stock equity would have been $2.3 billion and
$5.2 billion, respectively.
IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES
Year 2000 Problem. At midnight on December 31, 1999, unless the proper
modifications have been made, the program logic in many of the world's computer
systems will start to produce erroneous results because, among other things, the
systems will incorrectly read the date "01/01/00" as being January 1 of the year
1900 or another incorrect date. In addition, certain systems may fail to detect
that the year 2000 is a leap year. Problems can also arise earlier than January
1, 2000, as dates in the next millennium are entered into non-Year 2000
compliant programs.
Compliance Program. 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. Incorporated into this project were Resources' and
other Company subsidiaries' mainframe applications, infrastructures, embedded
systems and client-developed applications that will not be migrated into
existing or planned Company or Resources systems prior to the year 2000. The
evaluation of Year 2000 issues included those related to significant customers,
key vendors, service suppliers and other parties material to the Company's and
its subsidiaries' operations. In the course of this evaluation, the Company has
sought written assurances from such third parties as to their state of Year 2000
readiness.
State of Readiness. Work has been prioritized in accordance with business
risk. The highest priority has been assigned to activities that would disrupt
the physical delivery of energy (Priority 1); activities that would impact back
office activities such as billing (Priority 2); activities that would cause
inconvenience or productivity loss in normal business operations (e.g. air
conditioning systems and elevators) (Priority 3). All business units have
completed an analysis of critical systems and equipment that control the
production and delivery of energy, as well as corporate, departmental and
personnel systems and equipment. The remediation and replacement work on the
majority of IT
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systems, non-IT systems and infrastructure began in the first quarter of 1998
and is expected to be completed by the second quarter of 1999. Testing of these
systems began in the second quarter of 1998 and is scheduled to be completed in
third quarter of 1999. The following table illustrates the Company's completion
percentages for the Year 2000 activities as of February 28, 1999:
PRIORITY 1 PRIORITY 2 PRIORITY 3
-------------- -------------- ---------------
Assessment.............................................. 95% 86% 96%
Conversion.............................................. 86% 70% 91%
Testing................................................. 80% 61% 87%
Implementation.......................................... 76% 54% 75%
Costs to Address Year 2000 Compliance Issues. Based on current internal
studies, as well as recently solicited bids from various computer software
vendors, the Company estimates that the total direct cost of resolving the Year
2000 issue with respect to the Company and its subsidiaries will be between $35
and $40 million. This estimate includes approximately $7 million related to
salaries and expenses of existing employees and approximately $3 million in
hardware purchases that the Company expects to capitalize. In addition, the $35
to $40 million estimate includes approximately $2 million spent prior to 1998
and approximately $12 million during 1998. The remaining costs related to
resolving the Year 2000 issue are expected to be expended in 1999.
The Company expects to fund these expenditures through internal sources.
In September 1997, the Company entered into an agreement with SAP America,
Inc. (SAP) to license SAP proprietary R/3 enterprise software. The licensed
software includes customer care, finance and accounting, human resources,
materials management and service delivery components. The Company's purchase of
this software license and related computer hardware is part of its response to
changes in the electric utility and energy services industries, as well as
changes in the Company's businesses and operations resulting from the
acquisition of Resources and the Company's expansion into the energy trading and
marketing business. Although it is anticipated that the implementation of the
SAP system will have 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 and March 1999, and it is expected that the final portion of the
SAP system will be fully implemented by July 2000. The estimated costs of
implementing the SAP system is approximately $182 million, inclusive of internal
costs. In 1998, the Company and its subsidiaries spent $108 million of such
costs. In 1999, the Company and its subsidiaries expect to spend $59 million
with the remaining amounts to be spent in 2000.
The estimated Year 2000 project costs do not give effect to any future
corporate acquisitions or divestitures made by the Company or its subsidiaries.
Risks and Contingency Plans. The major systems which pose the greatest Year
2000 risks for the Company and its subsidiaries if implementation of the Year
2000 compliance program is not successful are the process control systems for
energy delivery systems; the time in use, demand and recorder metering system
for commercial and industrial customers; the outage analysis system; and the
power billing systems. The potential problems related to these systems are
temporary electric service interruptions to customers, temporary interruptions
in revenue data gathering and temporary poor customer relations resulting from
delayed billing. Although the Company does not believe that this scenario will
occur, the Company has considerable experience responding to emergency
situations, including computer failure. Existing emergency operations, disaster
recovery and business continuation plans are being enhanced to ensure
preparedness and to mitigate the long-term effect of such a scenario.
The North American Electric Reliability Council (NERC) is coordinating
electric utility industry contingency planning on a national level. Additional
contingency planning is being done at the regional electric reliability council
level. Reliant Energy HL&P filed a draft Year 2000 Contingency Plan with NERC
and with the Texas Utility Commission in December 1998. The draft plan addresses
restoration of electric service and related business processes, and is designed
to work in conjunction with the Emergency Operating Plan and with the plans of
NERC and ERCOT.
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A final contingency plan is scheduled to be complete by June 30, 1999. In
addition, Reliant Energy HL&P will participate in industry preparedness drills,
such as the two NERC drills scheduled to be held on April 9, 1999 and September
9, 1999.
The existing business continuity disaster recovery and emergency operations
plans are being reviewed and enhanced, and where necessary, additional plans
will be developed to include mitigation strategies and action plans specifically
addressing potential Year 2000 scenarios. The expected completion date for these
plans is June 30, 1999.
In order to assist in preparing for and mitigating the foregoing scenarios,
the Company intends to complete all mission critical Year 2000 remediation and
testing activity by the end of the second quarter of 1999. In addition, the
Company has initiated Year 2000 communications with significant customers, key
vendors, service suppliers and other parties material to the Company's
operations and is diligently monitoring the progress of such third parties' Year
2000 projects. The Company expects to meet with mission-critical third parties,
including suppliers, in order to ascertain and assess the relative risks of
Year-2000-related issues, and to mitigate such risks. Notwithstanding the
foregoing, the Company cautions that (i) the nature of testing is such that it
cannot comprehensively address all future combinations of dates and events and
(ii) it is impossible for the Company to assess with precision or certainty the
compliance of third parties with Year 2000 remediation efforts. Due to the
speculative and uncertain nature of contingency planning, there can be no
assurance that such plans actually will be sufficient to reduce the risk of
material impacts on the Company's and its subsidiaries' operations.
RISKS OF INTERNATIONAL OPERATIONS
The Company's international 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 international 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, through
Reliant Energy International's subsidiaries, owns 11.69% of the stock of Light
and, through its investment in Light, an 8.753% interest in the stock of
Metropolitana Electricidade de Sao Paulo S.A. (Metropolitana). The Company
accounts for its investment in Light under the equity method of accounting and
records its proportionate share, based on stock ownership, in the net income of
Light and its affiliates (including Metropolitana) as part of the Company's
consolidated net income.
At December 31, 1998, Light and Metropolitana had total borrowings of
approximately $3.2 billion denominated in non-local currencies. Because of the
devaluation of the Brazilian real subsequent to December 31, 1998, Light and
Metropolitana are expected to record a charge to March 31, 1999 earnings that
reflects the increase in the liability represented by their non-local currency
denominated bank borrowings relative to the Brazilian real. Because the Company
uses the Brazilian real as the functional currency in which it reports Light's
equity earnings, the resulting decrease in Light's earnings will also be
reflected in the Company's consolidated earnings to the extent of the Company's
11.69% ownership interest in Light. At December 31, 1998, one U. S. dollar could
be exchanged for 1.21 Brazilian reais. Using the exchange rate of 2.06 Brazilian
reais in effect at the end of February, and the average exchange rate in effect
since the end of the year, the Company estimates that its share of the after-tax
charge to be recorded by Light would be approximately $125 million. This
estimate does not reflect the possibility of additional fluctuations in the
exchange rate and does not include other non-debt-related impacts of Brazil's
currency devaluation on Light's and Metropolitana's future earnings.
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None of Light's or Metropolitana's tariff adjustment mechanisms are
directly indexed to the U.S. dollar or other non-local currencies. Each company
currently is evaluating various options including regulatory rate relief to
mitigate the impact of the devaluation of the Brazilian real. For example, the
long-term concession contracts under which Light and Metropolitana operate
contain mechanisms for adjusting electricity tariffs to reflect changes in
operating costs resulting from inflation. If the devaluation of the Brazilian
real results in an increase in the local rate of inflation and if an adjustment
to tariff rates is made promptly to reflect such increase, the Company believes
that the financial results of Light and Metropolitana should be protected, at
least in part, from the effects of devaluation. However, there can be no
assurance the implementation of such tariff adjustments will be timely or that
the economic impact of the devaluation will be completely reflected in increased
inflation rates.
Certain of Reliant Energy International's other foreign electric
distribution companies have incurred U.S. dollar and other non-local currency
indebtedness (approximately $71 million at December 31, 1998). 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 Project Capital Resources. In the
first quarter of 1999, approximately $117 million of Metropolitana's U.S. dollar
denominated debt will mature. In the second quarter of 1999, approximately $980
million of Light's and approximately $696 million of Metropolitana's U.S. and
non-local currency denominated bank debt will mature. In March 1999, Light
refinanced approximately $130 million of its U.S. dollar denominated debt
through a local - currency denominated loan. 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. The availability or terms of refinancing such
debt cannot be assured.
Currency fluctuation and instability affecting Latin America may also
adversely affect Reliant Energy International's ability to refinance its equity
investments with debt. In 1998, Reliant Energy International invested $411
million in Colombia and El Salvador. As of January 1999, $100 million of these
investments were refinanced with debt. Reliant Energy International intends to
refinance approximately $75 million more of such initial investments with debt.
ENVIRONMENTAL EXPENDITURES
The Company and its subsidiaries, including Resources, are subject to
numerous environmental laws and regulations, which require them 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.
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). The standards applicable
to Electric Operations' generating units in the Houston, Texas area will become
effective in November 1999. NOx reduction costs incurred by Electric Operations
totaled approximately $7 million in 1998. The Company estimates that Electric
Operations will incur approximately $8 million in 1999 and $10 million in 2000
for such expenditures. The Texas Natural Resources Conservation Commission
(TNRCC) has indicated that additional NOx reduction will be required after 2000;
however, since the magnitude and timing of these reductions have not yet been
established, it is impossible for the Company to estimate a reasonable range of
such expenditures at this time.
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In 1998, the Wholesale Energy spent approximately $100,000 in order to
comply with NOx reduction with respect to Southern California generating
facilities acquired by Power Generation from Southern California Edison (SCE) in
1998. In 1999, based on existing requirements, the Company projects that it will
spend an additional $100,000 on NOx reduction standards with respect to such
plants and approximately $1 million on continuous emission monitoring system
upgrades for such plants.
Site Remediation Expenditures. From time to time the Company and its
subsidiaries have received notices from regulatory authorities or others
regarding their status as potentially responsible parties in connection with
sites found to require remediation due to the presence of environmental
contaminants.
The Company's identified sites with respect to which it may be claimed to
have a remediation liability include several sites for which there is a lack of
current available information, including the nature and magnitude of
contamination, and the extent, if any, to which the Company may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can now be made for these sites.
Based on currently available information, the Company believes that such costs
ultimately 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 such
estimates. For information about specific sites that are the subject of
remediation claims, see Note 12(h) to the Company's Consolidated Financial
Statements and Note 8(g) to Resources' Consolidated Financial Statements, each
of which is incorporated herein by reference.
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 of Resources and others in the natural
gas industry to date and on the current regulations regarding remediation of
such sites, the Company and Resources believe 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 and its subsidiaries, see Notes 3, 4, 5 and 12 to the
Company's Consolidated Financial Statements and Note 8 to Resources'
Consolidated Financial Statements, which notes are incorporated herein by
reference.
8
9
NEW ACCOUNTING ISSUES
In 1998, the Company and Resources adopted SFAS No. 130, "Reporting
Comprehensive Income" (SFAS No. 130), SFAS No. 131, "Disclosures about Segments
of an Enterprise and Related Information" (SFAS No. 131) and SFAS No. 132,
"Employers Disclosures about Pensions and Other Postretirement Benefits" (SFAS
No. 132). For further discussion of these accounting statements, see Note 15 to
the Company's Consolidated Financial Statements and Note 9 to Resources'
Consolidated Financial Statements.
In 2000, the Company and Resources expect to adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133),
which establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities. The
Company is in the process of determining the effect of adoption of SFAS No. 133
on its consolidated financial statements.
In December 1998, The Emerging Issues Task Force of the Financial
Accounting Standards Board reached consensus on Issue 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue
98-10). EITF Issue 98-10 requires energy trading contracts to be recorded at
fair value on the balance sheet, with the changes in fair value included in
earnings. EITF Issue 98-10 is effective for fiscal years beginning after
December 15, 1998. The Company expects to adopt EITF Issue 98-10 in the first
quarter of 1999. The Company does not expect the implementation of EITF Issue
98-10 to be material to its consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
The Company and its subsidiaries have long-term debt, Company/ Resources
obligated mandatorily redeemable preferred securities of subsidiary trusts
holding solely junior subordinated debentures of the Company/Resources (Trust
Securities), securities held in the Company's nuclear decommissioning trust,
bank facilities, certain lease obligations and interest rate swaps which subject
the Company, Resources and certain of their subsidiaries to the risk of loss
associated with movements in market interest rates.
At December 31, 1998, the Company and certain of its subsidiaries had
issued fixed-rate long-term debt (excluding ACES) and Trust Securities
aggregating $5.0 billion in principal amount and having a fair value of $5.2
billion. These instruments are fixed-rate and, therefore, do not expose the
Company and its subsidiaries to the risk of earnings loss due to changes in
market interest rates (see Notes 8 and 9 to the Company's Consolidated Financial
Statements). However, the fair value of these instruments would increase by
approximately $260.6 million if interest rates were to decline by 10% from their
levels at December 31, 1998. In general, such an increase in fair value would
impact earnings and cash flows only if the Company and its subsidiaries were to
reacquire all or a portion of these instruments in the open market prior to
their maturity.
The Company and certain of its subsidiaries' floating-rate obligations
aggregated $1.8 billion at December 31, 1998 (see Note 8 to the Company's
Consolidated Financial Statements), inclusive of (i) amounts borrowed under
short-term and long-term credit facilities of the Company and its subsidiaries
(including the issuance of commercial paper supported by such facilities), (ii)
borrowings underlying Resources' receivables facility and (iii) amounts subject
to a master leasing agreement of Resources under which lease payments vary
depending on short-term interest rates. These floating-rate obligations expose
the Company, Resources and their subsidiaries 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, 1998 levels, the
Company's consolidated interest expense and expense under operating leases would
increase by a total of approximately $0.9 million each month in which such
increase continued.
As discussed in Notes 1(o), 4(c) and 13 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 $119.1 million as of December 31, 1998, of which
approximately 44% 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, 1998, 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 at this
time as a result of the Company's regulated status. 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.
Certain subsidiaries of the Company have entered into interest rate swaps
for the purpose of decreasing the amount of debt subject to interest rate
fluctuations. At December 31, 1998, these interest rate swaps had an aggregate
notional amount of $75.4 million, which the Company could terminate at a cost of
$3.2 million (see Notes 2 and 13 to the Company's Consolidated Financial
Statements). An increase of 10% in the December 31, 1998 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 and its
subsidiaries' earnings and cash flows only if all or a portion of the swap
instruments were terminated prior to their expiration.
12
10
As discussed in Note 8(h) to the Company's Consolidated Financial
Statements, 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, 1998, the Company could terminate the
option at a cost of $30.7 million. A decrease of 10% in the December 31, 1998
level of interest rates would not increase the cost of termination of the option
by a material amount to the Company.
The change in exposure to loss in earnings and cash flows related to
interest rate risk from December 31, 1997 to December 31, 1998 is not material
to the Company.
EQUITY MARKET RISK
The Company holds an investment in TW Preferred which is convertible into
Time Warner common stock (TW Common) as described in "Management's Discussion
and Analysis of Financial Condition and Results of Operations of the Company --
Certain Factors Affecting Future Earnings of the Company and its Subsidiaries --
Accounting Treatment of ACES" in Item 7 of this Form 10-K. As a result, the
Company is exposed to losses in the fair value of this security. For purposes of
analyzing market risk in this Item 7A, the Company assumed that the TW Preferred
was converted into TW Common. In addition, Resources' investment in the common
stock of Itron, Inc. (Itron) exposes the Company and Resources to losses in the
fair value of Itron common stock. A 10% decline in the market value per share of
TW Common and Itron common stock from the December 31, 1998 levels would result
in a loss in fair value of approximately $284.4 million and $1.1 million,
respectively.
The Company's and its subsidiaries' ability to realize gains and losses
related to the TW Preferred and the Itron common stock is limited by the
following: (i) the TW Preferred is not publicly traded and its sale is subject
to certain limitations and (ii) the market for the common stock of Itron is
fairly illiquid.
The ACES expose the Company to accounting losses as the Company is required
to record in Other Income (Expense) an unrealized accounting loss equal to (i)
the aggregate amount of the increase in the market price of TW Common above
$27.7922 as applicable to all ACES multiplied by (ii) 0.8264. Prior to the
conversion of the TW Preferred into TW Common, such loss would affect earnings.
After conversion, such loss would be recognized as an adjustment to common stock
equity through a reduction of other comprehensive income. However, there would
be an offsetting increase in common stock equity through an increase in
accumulated other comprehensive income on the Company's Statements of
Consolidated Retained Earnings and Comprehensive Income for the fair value
increase in the investment in TW Common. For additional information on the
accounting treatment of the ACES and related accounting losses recorded in 1998,
see Note 1(n) to the Company's Consolidated Financial Statements. An increase of
15% in the price of the TW Common above its December 31, 1998 market value of
$62.062 per share would result in the recognition of an additional unrealized
accounting loss (net of tax) of approximately $229.1 million. The Company
believes that this additional unrealized loss for the ACES would be more than
economically hedged by the unrecorded unrealized gain relating to the increase
in the fair value of the TW Common underlying the investment in TW Preferred
since the date of its acquisition.
For a discussion of the non-cash, unrealized accounting loss recorded in
1998 and 1997 related to the ACES, see "-- Certain Factors Affecting Future
Earnings of the Company and its Subsidiaries -- Accounting Treatment of ACES" in
Item 7 of this Form 10-K.
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, 1998. 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, 1998, 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 a result of the Company's regulated status as
discussed above under "--Interest Rate Risk."
FOREIGN CURRENCY EXCHANGE RATE RISK
As further described in "Certain Factors Affecting Future Earnings of the
Company and Its Subsidiaries -- Risks of International Operations" in Item 7 of
this Form 10-K, the Company, through Reliant Energy International invests in
certain foreign operations which to date have been primarily in South America.
As of December 31, 1998, the Company's Consolidated Balance Sheets reflected
$1.1 billion of foreign investments, a substantial portion of which represent
investments accounted for under the equity method. These foreign investments
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. For further discussion of the accounting for foreign
currency adjustments, see Note 1(p) in the Notes to the Company's Consolidated
Financial Statements. The cumulative translation loss of $34 million, recorded
as of December 31, 1998, will be realized as a loss in earnings and cash flows
only upon the disposition of the related investment. The foreign currency loss
in earnings and cash flows related to debt obligations held by foreign
operations in currencies other than their own functional currencies was not
material to the Company as of December 31, 1997.
13
11
In addition, certain of Reliant Energy International'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, 1998, Light and Metropolitana had borrowings
of approximately $3.2 billion denominated in non-local currencies. Because of
the devaluation of the Brazilian real subsequent to December 31, 1998, Light and
Metropolitana are expected to record a charge to earnings for the quarter ended
March 31, 1999, primarily related to foreign currency transaction losses on
their non-local currency denominated debt. For further discussion and analysis
of the possible effect on the Company's Consolidated Financial Statements, see
"Certain Factors Affecting Future Earnings of the Company and Its Subsidiaries
- -- Risks of International Operations" in Item 7 of this Form 10-K.
The company attempts to manage and mitigate this foreign risk by properly
balancing the higher 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 all its financial plans. In addition, where possible, Reliant
Energy International 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 2 to the Company's Consolidated Financial
Statements, certain of the Company's subsidiaries utilize a variety of
derivative financial instruments (Derivatives), including swaps 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, Resources and certain
subsidiaries of the Company and Resources enter 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 and
transportation 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, a
subsidiary of Resources, 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 subsidiaries of the Company and Resources as of December 31, 1998, a
decrease of 10% in the market prices of natural gas and electric power from
year-end levels would decrease the fair value of these instruments by
approximately $3 million. As of December 31, 1997, a decrease of 10% in the
prices of natural gas would have resulted in a loss of $7 million in fair values
of the Energy Derivatives (other than for trading purposes).
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 and its subsidiaries' physical purchases and sales
of natural gas and electric power to which the hedges relate. The portfolio of
Energy Derivatives held for hedging purposes is no greater than the notional
quantity of the expected or committed transaction volume of physical commodities
with equal and opposite commodity price risk for the same time periods.
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 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,
physical forwards, swaps, options and exchange-traded futures, this subsidiary
is exposed to losses in fair value due to changes in the price and volatility of
the underlying derivatives. During the year ended December 31, 1998 and 1997,
the highest, lowest and average monthly value-at-risk in the Trading Derivative
portfolio was less than $5 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 the delta approximation for options
positions.
The Company has established a Corporate Risk Oversight Committee comprised
of corporate and business segment officers that oversees all corporate price and
credit risk activities, including derivative trading activities discussed above.
The committee's duties are to establish the Company's policies and to monitor
and ensure compliance with risk management policies and procedures and the
trading limits established by the Company's board of directors.
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COMPANY 10-K NOTES
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(c) Regulatory Assets and Other Long-Lived Assets.
The Company and certain subsidiaries of Resources apply the accounting
policies established in SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71), to the accounts of Electric Operations,
Natural Gas Distribution and the Interstate Pipeline operations of a subsidiary
of Resources. 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 the rate
regulated company is recovering or expects to recover such costs in rates
charged to its customers.
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheet as of December 31, 1998, detailed by
Electric Operations and other segments.
ELECTRIC TOTAL
OPERATIONS OTHER COMPANY
---------- ----- -------
(MILLIONS OF DOLLARS)
Deferred plant costs-- net............................................ $ 536 $ $ 536
Recoverable project costs-- net....................................... 55 55
Regulatory tax asset-- net............................................ 418 418
Unamortized loss on reacquired debt................................... 140 140
Fuel-related debits/credits-- net..................................... (15) (15)
Other deferred debits................................................. 54 12 66
--------- -------- --------
Total....................................................... $ 1,188 $ 12 $ 1,200
--------- -------- --------
If, as a result of changes in regulation or competition, the Company's and
Resources' ability to recover these assets and liabilities would not be assured,
then pursuant to SFAS No. 101, "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 and Resources would be required to write off or
write down such regulatory assets and liabilities, unless some form of
transition cost recovery continues through rates established and collected for
their remaining regulated operations. In addition, the Company and Resources
would be required to determine any impairment to the carrying costs of
deregulated plant and inventory assets. In order to reduce exposure to
potentially stranded costs related to generation assets, Electric Operations
redirected $195 million of depreciation in 1998 from transmission, distribution
and general plant assets to generation assets. Such redirection is in accordance
with the Company's transition to competition plan (Transition Plan) described in
Note 1(f). If Electric Operations was required to apply SFAS No. 101 to the
generation portion of its business only, the cumulative amount of redirected
depreciation of $195 million would become a regulatory asset of the transmission
and distribution portion of its business.
Effective January 1, 1996, the Company and Resources adopted SFAS No. 121.
SFAS No. 121 requires that long-lived assets and certain identifiable
intangibles to be held and used or disposed of by an entity be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Adoption of the standard did
not result in a write-down of the carrying amount of any asset on the books of
the Company or Resources.
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 97-4). EITF 97-4 concluded that the
application of SFAS No. 71 to a segment which is subject to a deregulation plan
should cease when the legislation and enabling rate order contain sufficient
detail for the utility to reasonably determine how the plan will affect the
segment to be deregulated. In addition, EITF 97-4 requires the regulatory assets
and liabilities to be allocated to the applicable portion of the electric
utility from which the source of the regulated cash flows will be derived. As a
part of the Transition Plan, the Company has agreed to support future
legislation providing for retail customer choice and other provisions consistent
with those in the 1997 proposed Texas legislation. At this time, the Company is
unable to make any predictions as to the details of legislation being considered
by the Texas legislature or the likelihood that such legislation will ultimately
be enacted. Although the Company has determined that no impairment loss or
write-offs of regulatory assets or carrying costs of plant and inventory assets
need to be recognized for applicable assets of Electric Operations as of
December 31, 1998, this conclusion may change in the future (i) as competition
influences wholesale and retail pricing in the electric utility industry, (ii)
depending on regulatory action, if any and (iii) depending on legislation, if
any, that is passed.
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(f) Depreciation and Amortization Expense.
The Company's consolidated depreciation expense for 1998 was $548 million
compared to $475 million for 1997 and $410 million for 1996.
In June 1998, the Public Utility Commission of Texas (Texas Utility
Commission) issued an order approving the Transition Plan filed by Electric
Operations in December 1997. In order to reduce Electric Operations' exposure
to potentially stranded costs related to generation assets, the Transition Plan
permits the redirection to generation assets of depreciation expense that
Electric Operations otherwise would apply to transmission, distribution and
general plant assets. In addition, the Transition Plan provides that all
earnings above a 9.844% overall annual rate of return on invested capital be
used to recover Electric Operations' investment in generation assets. Electric
Operations implemented the Transition Plan effective January 1, 1998 and
pursuant to its terms, recorded an aggregate of $194 million in additional
depreciation and $195 million in redirected depreciation in 1998.
The Company's depreciation and amortization expenses included $50 million
of additional depreciation relating to the South Texas Project Electric
Generating Station (South Texas Project) in both 1997 and 1996 and goodwill
amortization relating to the acquisition of Resources of $55 million in 1998
and $22 million in 1997. For additional information regarding the operation of
goodwill in connection with the Merger, see Note 1(b) above. The depreciation
expense recorded for the South Texas Project was made pursuant to the terms of
the Company's 1995 rate case settlement (1995 Rate Case Settlement), which
permitted the Company to write down as much as $50 million per year of its
investment in the South Texas Project through December 31, 1999. These
write-downs are treated under the 1995 Rate Case Settlement as reasonable and
necessary expenses for purposes of any future earnings reviews or other
proceedings.
In 1998, 1997 and 1996, the Company, as permitted by the 1995 Rate Case
Settlement, also amortized $4 million, $66 million and $50 million (pre-tax),
respectively, of its $153 million investment in certain lignite reserves
associated with a canceled generating station. The Company's remaining
investment in the canceled generating station and certain lignite reserves will
be amortized fully no later than December 31, 2002.
(n) Investments in Time Warner Securities.
The Company owns 11 million shares of non-publicly traded Time Warner
convertible preferred stock (TW Preferred). The TW Preferred is redeemable after
July 6, 2000, has an aggregate liquidation preference of $100 per share (plus
accrued and unpaid dividends), is entitled to annual dividends of $3.75 per
share until July 6, 1999, is currently convertible by the Company and after July
6, 1999 is exchangeable by Time Warner into approximately 45.8 million shares of
Time Warner common stock (TW Common). Each share of TW Preferred is entitled to
two votes (voting together with the holders of the TW Common as a single class).
The Company has accounted for its investment in TW Preferred under the cost
method at a value of $990 million on the Company's Consolidated Balance Sheets.
Dividends on these securities are recognized as income at the time they are
earned. The Company recorded pre-tax dividend income with respect to the Time
Warner securities of $41.3 million in 1998 and 1997 and $41.6 million in 1996.
To monetize its investment in the TW Preferred, the Company sold in July
1997, 22.9 million of ACES. At maturity in July 2000, the principal amount of
the ACES will be mandatorily exchangeable by the Company into either (i) a
number of shares of TW Common based on an exchange rate or (ii) cash having an
equal value. Subject to adjustments that may result from certain dilution
events, the exchange rate for each ACES is determined as follows: (i) 1.6528
shares of TW Common if the price of TW Common at maturity (Maturity Price) is at
least $27.7922 per share, (ii) a fractional share of TW Common such that the
fractional share will have a value equal to $22.96875 if the Maturity Price is
less than $27.7922 but greater than $22.96875 and (iii) one share of TW Common
if the Maturity Price is not more than $22.96875. The closing price of TW Common
was $62.062 per share on December 31, 1998.
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 Preferred 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 redemption notice. The redemption price
may be paid in cash or in shares of TW Common or a combination of the two.
As a result of the issuance of the ACES, a portion of the increase in the
market value above $27.7922 per share of TW Common results in non-cash,
unrealized accounting losses to the Company for the ACES, pending the conversion
of the Company's TW Preferred into TW Common. For example, prior to the
conversion, when the market price of TW Common increases above $27.7922, the
Company records in Other Income (Expense) an unrealized, non-cash accounting
loss for the ACES equal to (i) the aggregate amount of such increase as
applicable to all ACES multiplied by (ii) 0.8264. In accordance with generally
accepted accounting principles, this accounting loss (which reflects the
unrealized increase in the Company's indebtedness with respect to the ACES) may
not be offset by accounting recognition of the increase in the market value of
the TW Common that underlies the TW Preferred. Upon conversion of the TW
Preferred (anticipated to occur in July 1999), the Company will begin recording
future unrealized net changes in the market prices of the TW Common and the ACES
as a component of common stock equity and other comprehensive income.
As of December 31, 1998 and 1997, the market price of TW Common was $62.062
and $31.00 per share, respectively. Accordingly, the Company recognized an
increase of $1.2 billion in 1998 and $121 million in 1997 in the unrealized
liability relating to its ACES indebtedness (which resulted in an after-tax
earnings reduction of $764 million or $2.69 basic earnings per share and $79
million or $.31 basic earnings per share, respectively). The Company believes
that the cumulative unrealized loss for the ACES of approximately $1.3 billion
is more than economically hedged by the approximately $1.8 billion unrecorded
unrealized gain at December 31, 1998 relating to the increase in the fair value
of the TW Common underlying the investment in TW Preferred since the date of its
acquisition. Any gain related to the increase in fair value of TW Common would
be recognized as a component of net income upon the sale of the TW Preferred or
the shares of TW Common into which such TW Preferred is converted. As of March
11, 1999, the price of TW Common was $70.75 per share which would have resulted
in the Company recognizing an additional increase of $329 million in the
unrealized liability relating to its ACES indebtedness. The related unrecorded
unrealized gain as of March 11, 1999 would have been computed as an additional
$398 million.
(p) Foreign Currency Adjustments
International 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 and other comprehensive income. When
the U.S. dollar is the functional currency, the financial statements of
International 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. 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 unconsolidated affiliates, see Note 5. For additional information about the
Company's investments in Brazil and the devaluation of the Brazilian real in
January 1999, see Note 16(a).
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(r) Change in Accounting Principle.
In the fourth quarter of 1998, the Company adopted mark-to-market
accounting for all of the energy price risk management and trading activities of
Reliant Energy Services. Under mark-to-market accounting, the Company records
the fair value of energy-related derivative financial instruments, including
physical forward contracts, swaps, options and exchange-traded futures contracts
at each balance sheet date. Such amounts are recorded in the Company's
Consolidated Balance Sheet as price risk management assets, price risk
management liabilities, deferred debits and deferred liabilities. The realized
and unrealized gains (losses) are recorded as a component of operating revenues
in the Company's Consolidated Statements of Income. The Company has applied
mark-to-market accounting retroactively to January 1, 1998. This change was made
in order to adopt a generally accepted accounting methodology that provided
consistency between financial reporting and the methodology used in all reported
periods by the Company in managing its trading activities. There was no material
cumulative effect resulting from the accounting change.
The Company will adopt Emerging Issues Task Force Issue 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" in the
first quarter of 1999 for Reliant Energy Services' trading activities. The
Company does not expect the implementation of EITF Issue 98-10 to be material
to its consolidated financial statements.
(2) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
The Company, through Reliant Energy Services, offers energy price risk
management services primarily in the natural gas, electric and crude oil and
refined product industries. Reliant Energy Services provides these services by
utilizing, a variety of derivative financial instruments, including fixed and
variable-priced physical forward contracts, fixed-price swap agreements,
variable-price swap agreements, exchange-traded energy futures and option
contracts, and swaps and options traded in the over-the-counter financial
markets (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, Reliant Energy Services applied hedge accounting to certain
physical commodity activities that qualified for hedge accounting. In 1998,
Reliant Energy Services adopted mark-to-market accounting for all of its price
risk management and trading activities. Accordingly, as of such date such
Trading Derivatives are recorded at fair value with realized and unrealized
gains (losses) recorded as a component of operating revenues in the Company's
Consolidated Statements of Income. The recognized, unrealized balance is
recorded as price risk management assets/liabilities and deferred
debits/credits on the Company's Consolidated Balance Sheets (See Note 1(r)).
The notional quantities, maximum terms and the estimated fair value of
Trading Derivatives at December 31, 1998 are presented below (volumes in
billions of British thermal units equivalent (BBtue) and dollars in millions):
VOLUME-FIXED
VOLUME-FIXED PRICE MAXIMUM
1998 PRICE PAYOR RECEIVER TERM (YEARS)
---- ----------- -------- ------------
Natural gas.................................................. 937,264 977,293 9
Electricity.................................................. 122,950 124,878 3
Crude oil and products....................................... 205,499 204,223 3
AVERAGE FAIR
FAIR VALUE VALUE (a)
---------------------- ----------------------
1998 ASSETS LIABILITIES ASSETS LIABILITIES
---- ------ ----------- ------ -----------
Natural gas.............................................. $ 224 $ 213 $ 124 $ 108
Electricity.............................................. 34 33 186 186
Crude oil and products................................... 29 23 21 17
------ ----------- ------ -----------
$ 287 $ 269 $ 331 $ 311
====== =========== ====== ===========
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15
The notional quantities, maximum terms and the estimated fair value of
derivative financial instruments at December 31, 1997 are presented below
(volumes in BBtue and dollars in millions):
VOLUME-FIXED
VOLUME-FIXED PRICE MAXIMUM
1997 PRICE PAYOR RECEIVER TERM (YEARS)
---- ----------- -------- ------------
Natural gas.................................................. 85,701 64,890 4
Electricity.................................................. 40,511 42,976 1
AVERAGE FAIR
FAIR VALUE VALUE (a)
---------------------- ----------------------
1997 ASSETS LIABILITIES ASSETS LIABILITIES
---- ------ ----------- ------ -----------
Natural gas.............................................. $ 46 $ 39 $ 56 $ 48
Electricity.............................................. 6 6 3 2
------ ----------- ------ -----------
$ 52 $ 45 $ 59 $ 50
====== =========== ====== ===========
- ---------
(a) Computed using the ending balance of each month.
In addition to the fixed-price notional volumes above, Reliant Energy
Services also has variable-priced agreements, as discussed above, totaling
1,702,977 and 101,465 BBtue as of December 31, 1998 and 1997, 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 value shown in the table above at December 31, 1998 and
substantially all of the fair value at December 31, 1997 have been recognized in
income. The fair value as of December 31, 1998 and 1997 was estimated using
quoted prices where available and considering the liquidity of the market for
the Trading Derivatives. The prices are subject to significant changes based on
changing market conditions.
At December 31, 1998, $22 million of the fair value of the assets and $41
million of the fair value of the liabilities are recorded as long-term on
deferred debits and deferred credits, respectively on the Company's Consolidated
Balance Sheets.
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 and its subsidiaries' 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 Reliant Energy Services
as of December 31, 1998.
INVESTMENT
GRADE (1) TOTAL
---------------------------------
(Thousands of Dollars)
------------ ------------
Energy marketers....................................... $ 102,458 $ 123,779
Financial institutions................................. 61,572 61,572
Gas and electric utilities............................. 46,880 48,015
Oil and gas producers.................................. 7,197 8,323
Industrials............................................ 1,807 3,233
Independent power producers............................ 1,452 1,463
Others................................................. 45,421 46,696
------------ ------------
Total............................................. $ 266,787 $ 293,081
============
Credit and other reserves.............................. (6,464)
------------
Energy price risk management assets (2)................ $ 286,617
============
- ---------
(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) The Company has credit risk exposure with respect to two investment grade
customers, each of which represents an amount greater than 5% but less than
10% of Price Risk Management Assets.
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16
(b) Non-Trading Activities.
To reduce the risk from market fluctuations in the price of electric power,
natural gas and related transportation, the Company, Resources and certain of
its subsidiaries enter 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, although usage to date for this
purpose has not been material. The Company applies hedge accounting with respect
to its derivative financial instruments.
Certain subsidiaries of the Company also utilize 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 utilize such
derivatives to effectively fix the interest rate on debt expected to be issued
for refunding purposes.
For transactions involving either Energy Derivatives or interest-rate
derivatives, hedge accounting is applied only if the derivative (i) reduces the
price 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.
Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in the Company's Consolidated Statements of
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, 1998, subsidiaries of Resources were fixed-price payors and
fixed-price receivers in Energy Derivatives covering 42,498 billion British
thermal units (Bbtu) and 3,930 BBtu of natural gas, respectively. At December
31, 1997, subsidiaries of Resources were fixed-price payors and fixed-price
receivers in Energy Derivatives covering 38,754 BBtu and 7,647 BBtu of natural
gas, respectively. Also, at December 31, 1998 and 1997, subsidiaries of
Resources were parties to variable-priced Energy Derivatives totaling 21,437
Bbtu and 3,630 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 and its
subsidiaries' 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
13 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.
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17
(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 and its subsidiaries' 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 and its
subsidiaries have 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 and/or its subsidiaries, as the case may be, enter into such contracts
primarily with those counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively. For long-term arrangements, the Company
and its subsidiaries periodically review 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 or 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 loss 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 prohibit the use of leveraged financial instruments.
The Company has established a Corporate Risk Oversight Committee, comprised
of corporate and business segment officers, to oversee all corporate price and
credit risks, including Reliant Energy Services' trading, marketing and risk
management activities. The Corporate Risk Oversight Committee's responsibilities
include reviewing the Company's and its subsidiaries' hedging, trading and price
risk management strategies, activities and limits and monitoring to ensure
compliance with the Company's risk management policies and procedures and
trading limits established by the Company's board of directors.
(3) RATE MATTERS
(a) Electric Proceedings.
The Texas Utility Commission has original (or in some cases appellate)
jurisdiction over Electric Operations' electric rates and services. Texas
Utility Commission orders may be appealed to a District Court in Travis County,
and from that court's decision an appeal may be taken to the Court of Appeals
for the 3rd District at Austin (Austin Court of Appeals). Discretionary review
by the Supreme Court of Texas may be sought from decisions of the Austin Court
of Appeals. In the event that the courts ultimately reverse actions of the Texas
Utility Commission, such matters are remanded to the Texas Utility Commission
for action in light of the courts' orders.
(b) 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 information about additional depreciation of generation assets and
redirecting depreciation pursuant to the Transition Plan, see Note 1(f).
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. Because of the number of variables that can affect
the ultimate resolution of an appeal of Commission orders, the Company is not in
a position at this time to predict the outcome of this matter or the ultimate
effect that adverse action by the courts could have on the Company.
(4) 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, 1998, the Company's investment in the South Texas Project
(including AFUDC) was $1.4 billion (net of $1.1 billion accumulated
depreciation). The Company's investment in nuclear fuel (including AFUDC) was
$41 million (net of $230 million amortization) as of such date.
6
18
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 operation responsibility for the
South Texas Project to the South Texas Nuclear Operating Company (STPNOC).
STPNOC is managed by a board of 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 $16.5 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, such as the South Texas Project, was $9.145
billion as of December 31, 1998. 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 $83.9 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(o). In May 1994, an outside consultant
estimated the Company's portion of decommissioning costs to be approximately
$318 million (1994 dollars). 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, changes in regulatory and accounting requirements, changes in
technology and changes in costs of labor, materials and equipment. An update of
the 1994 study is in the process of being completed.
(d) Assessment Fees for Spent Fuel Disposal and Enrichment and Decommissioning.
By contract, the United States Department of Energy (DOE) has committed
itself ultimately to take possession of all spent fuel generated by the South
Texas Project. The DOE contract currently requires payment of a spent fuel
disposal fee on nuclear plant-generated electricity of one mill (one-tenth of a
cent) per net KWH sold. This fee is subject to adjustment to ensure full cost
recovery by the DOE. The Energy Policy Act also includes a provision that
assesses a fee upon domestic utilities that purchased nuclear fuel enrichment
services from the DOE before October 24, 1992. The South Texas Project's
assessment is approximately $2 million per year (subject to escalation for
inflation). The Company has a remaining estimated liability of $5 million for
such assessments.
7
19
(e) 1996 Settlement of South Texas Project Litigation.
In 1996, the Company recorded an aggregate $95 million ($62 million net of
tax) charge in connection with various settlements of lawsuits filed by
co-owners of the South Texas Project. For information about the execution of an
operations agreement with the City of San Antonio in connection with one of
these settlements, see Note 12(c).
(5) EQUITY INVESTMENTS AND ADVANCES TO UNCONSOLIDATED SUBSIDIARIES
The Company accounts for affiliate investments of its subsidiaries under
the equity method of accounting where (i) the subsidiary's ownership interest in
the affiliate ranges from 20% to 50%, (ii) the ownership interest is less than
20% but the subsidiary exercises significant influence over operating and
financial policies of such affiliate or (iii) the subsidiary's ownership
interest in the affiliate exceeds 50% but the subsidiary does not exercise
control over the affiliate.
The Company's and its subsidiaries' equity investments and advances in
unconsolidated subsidiaries at December 31, 1998 and 1997 were $1 billion and
$704 million, respectively. The Company's and its subsidiaries' equity income
from these investments, included in International revenues and other net income,
was $71 million, $49 million and $17 million in 1998, 1997 and 1996,
respectively. Dividends received from the investments amounted to $44 million
and $46 million in 1998 and 1997, respectively. No dividends were received from
these investments in 1996.
(a) International.
In April 1998, Light ServiHos de Eletricidade S.A. (Light), a
Brazilian corporation in which Reliant Energy International, Inc. (Reliant
Energy International) indirectly owns an 11.69% common stock interest, purchased
74.88% of the common stock of Metropolitana Eletricidade de Sao Paulo S.A.
(Metropolitana), an electric distribution company that serves the metropolitan
area of Sao Paulo, Brazil. The purchase price for the shares was approximately
$1.8 billion and was financed with proceeds from bank borrowings. As of December
31, 1998, Light and Metropolitana had approximately $3.2 billion in non-local
currency denominated borrowings. For information regarding foreign currency
adjustments, see Note 1(p). For information about the devaluation of the
Brazilian real in January 1999, see Note 16(a).
In May 1997, Reliant Energy International 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 International sold its 63% ownership
interest in an Argentine affiliate and certain related assets for approximately
$243 million. Reliant Energy International 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.
In 1998, a subsidiary of Reliant Energy International acquired for
approximately $150 million, equity interests (currently ranging from
approximately 36% to 45%) in three electric distribution systems located in El
Salvador. Corporacion EDC S.A.C.A. (CEDC), Reliant Energy International's
partner in this venture, acquired majority interests in the systems when they
were privatized in early 1998. On June 30, 1998, CEDC closed on the sale of
approximately half of its interests in the systems to a subsidiary of Reliant
Energy International.
In August 1998, Reliant Energy International and CEDC jointly acquired,
through subsidiaries, 65% of the stock of two Colombian electric distribution
companies, Electricaribe and Electrocosta. The shares of these companies are
indirectly held by an offshore holding company jointly owned by special purpose
subsidiaries of CEDC and Reliant Energy International.
The purchase price for the joint investment in Electricaribe and
Electrocosta was approximately $522 million, excluding transaction costs. The
purchase price was funded with capital contributions from Reliant Energy
International and CEDC and a U.S. $200 million loan obtained by the holding
company from a United States bank. A $100 million advance on the loan was
obtained in October 1998 with subsequent advances of $25 million and $75 million
obtained in December 1998 and January 1999, respectively. The loan will mature
on October 31, 2003. Reliant Energy International funded its capital
contributions with a portion of the proceeds from the sale of the Argentine
affiliate discussed above and capital contributions from the Company. Under the
terms of a support agreement, Reliant Energy International and CEDC have agreed,
among other things, to repurchase up to U.S. $50 million of the loan from the
bank to the extent that the bank is unable to syndicate that portion of the loan
to other banks on or prior to June 15, 1999.
In June 1997, a consortium of investors which included a subsidiary of
Reliant Energy International, acquired for $496 million a 56.7% controlling
ownership interest in Empresa de Energia del Pacifico S.A.E.S.P. (EPSA), an
electric utility system serving the Valle de Cauca province of Colombia,
including the area surrounding the city of Cali. Reliant Energy International
contributed $152 million of the purchase price for a 28.35% ownership interest
in EPSA. In addition to its distribution facilities, EPSA owns 850 MW of
electric generation capacity.
8
20
Reliant Energy International has accounted for these transactions under
purchase accounting and has recorded its investments and its interest in the
affiliates' earnings after the acquisition dates using the equity method. The
purchase prices were allocated, on a preliminary basis, using the estimated fair
market values of the assets acquired and the liabilities assumed as of the dates
of acquisition. The differences between the amounts paid and the underlying fair
values of the net assets acquired are being amortized as a component of earnings
attributable to unconsolidated affiliates over the estimated lives of the
projects ranging from 30 to 40 years. Purchase price adjustments to fixed assets
are being amortized over the underlying assets' estimated useful lives.
(b) Combined Financial Statement Data of Equity Investments and Advances to
Unconsolidated Subsidiaries.
The following table sets forth certain summarized financial information of
the Company's unconsolidated affiliates as of December 31, 1998 and 1997 and for
the years then ended or periods from the respective affiliates' acquisition date
through December 31, 1998, 1997 and 1996, if shorter:
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
($ IN THOUSANDS)
Income Statement:
Revenues....................... $ 2,449,335 $ 2,011,927 $ 994,743
Operating Expenses............. 1,762,166 1,460,248 768,993
Net Income..................... 514,005 403,323 149,038
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997
---------------- ----------------
($ IN THOUSANDS)
Balance Sheet:
Current Assets................... $ 1,841,857 $ 726,997
Noncurrent Assets................ 13,643,747 5,791,858
Current Liabilities.............. 4,074,603 566,596
Noncurrent Liabilities........... 6,284,821 1,398,385
Owner's Equity................... 5,126,180 4,553,874
(8) LONG-TERM DEBT AND SHORT-TERM BORROWINGS
(c) FinanceCo and FinanceCo II Credit Facilities.
In August 1997, a limited partnership special purpose subsidiary of the
Company (FinanceCo) established a five-year, $1.644 billion revolving credit
facility (FinanceCo Facility). The FinanceCo Facility supported $1.360 billion
in commercial paper borrowings by FinanceCo at December 31, 1998 recorded as
notes payable on the Company's Consolidated Balance Sheet. The weighted average
interest rate of these borrowings was 5.88% at December 31, 1998, and 6.15%
at December 31, 1997.
Borrowings under the FinanceCo Facility bear interest at a rate based upon
the London interbank offered rate (LIBOR) plus a margin, a base rate or at a
rate determined through a bidding process. The FinanceCo Facility may be used
(i) to support the issuance of commercial paper or other short-term indebtedness
of FinanceCo, (ii) subject to certain limitations, to finance purchases of
Company common stock and (iii) subject to certain limitations, to provide funds
for general purposes of FinanceCo, including the making of intercompany loans
to, or securing letters of credit for the benefit of, FinanceCo's affiliates.
The FinanceCo Facility requires the Company to maintain a ratio of
consolidated indebtedness for borrowed money to consolidated capitalization (as
defined) that does not exceed 0.65:1.00. The FinanceCo Facility also contains
restrictions applicable to the Company and certain of its subsidiaries with
respect to, among other things, (i) liens, (ii) consolidations, mergers and
dispositions of assets, (iii) dividends and purchases of common stock, (iv)
certain types of investments and (v) certain changes in its business. The
FinanceCo Facility contains customary covenants and default provisions
applicable to FinanceCo and its subsidiaries, including limitations on, among
other things, additional indebtedness (other than certain permitted
indebtedness), liens and certain investments or loans.
Subject to certain conditions and limitations, the Company is required to
make cash payments from time to time to FinanceCo from excess cash flow (as
defined in the FinanceCo Facility) to the extent necessary to enable FinanceCo
to meet its financial obligations. At December 31, 1998, commercial paper
supported by the FinanceCo Facility was secured by pledges of (i) all of the
limited and general partner interests of FinanceCo, (ii) the Series B Preference
Stock and (iii) certain intercompany notes held by FinanceCo. The obligations
under the FinanceCo Facility are not secured by the utility assets of the
Company or Resources or by the Company's investment in Time Warner securities.
In March 1998, a limited partnership special purpose subsidiary of the
Company (FinanceCo II) executed a $150 million credit agreement (FinanceCo II
Facility) which terminated March 2, 1999. Proceeds from $150 million of
borrowings under the FinanceCo II Facility were used to fund a portion of the
April 1998 purchase by Reliant Energy Power Generation, Inc. (Power Generation)
of four electric generation plants. Borrowings under the FinanceCo II Facility
bore interest at LIBOR-based and negotiated rates. At December 31, 1998,
FinanceCo II had $150 million of borrowings under this facility at an interest
rate of 5.75%. In March 1999, the $150 million of borrowings under the FinanceCo
II facility were paid at maturity with borrowings under the FinanceCo facility.
9
21
(d) Company Credit Facility.
The Company meets its short-term financing needs primarily through sales of
commercial paper supported by a $200 million revolving credit facility.
Borrowings under the facility are unsecured and a facility fee is paid. At
December 31, 1998, there was no outstanding commercial paper and there were no
outstanding borrowings under the bank facility.
(9) TRUST SECURITIES
(a) Company.
In February 1997, two Delaware statutory business trusts (Reliant Trusts)
established by the Company issued (i) $250 million of preferred securities and
(ii) $100 million of capital securities, respectively. The preferred securities
have a distribution rate of 8.125% payable quarterly in arrears, a stated
liquidation amount of $25 per preferred security and must be redeemed by March
2046. The capital securities have a distribution rate of 8.257% payable
quarterly in arrears, a stated liquidation amount of $1,000 per capital security
and must be redeemed by February 2037.
The Reliant Trusts sold the preferred and capital securities to the public
and used the proceeds to purchase $350 million aggregate principal amount of
subordinated debentures (Debentures) from the Company having interest rates
corresponding to the distribution rates of the securities and maturity dates
corresponding to the mandatory redemption dates of the securities. The Reliant
Trusts are accounted for as wholly owned consolidated subsidiaries of the
Company. The Debentures represent the Reliant Trusts' sole assets and its entire
operations. The Company has fully and unconditionally guaranteed, on a
subordinated basis, each Trust's obligations, including the payment of
distributions and all other payments due with respect to the respective
preferred and capital securities. The preferred and capital securities are
mandatorily redeemable upon the repayment of the related Debentures at their
stated maturity or earlier redemption.
Subject to certain limitations, the Company has the option of deferring
payments of interest on the Debentures held by the Reliant Trusts. If and for as
long as interest payments on the Debentures have been deferred, or an event of
default under the indenture relating thereto has occurred and is continuing, the
Company may not pay dividends on its capital stock. As of December 31, 1998, no
interest payments on the Debentures had been deferred.
(12) COMMITMENTS AND CONTINGENCIES
(a) Commitments.
The Company has various commitments for capital expenditures, fuel,
purchased power, cooling water 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. The Company's and its subsidiaries' 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.
The Company 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 are approximately
$210 million in 1999, $187 million in 2000 and $188 million in 2001.
Additionally, minimum payment obligations for lignite mining and lease
agreements are approximately $9 million for 1999, $10 million for 2000 and $10
million for 2001. Minimum payment obligations for both natural gas purchase and
storage contracts associated with Electric Operations are approximately $10
million in 1999, $9 million in 2000 and $9 million in 2001.
The Company also has commitments to purchase firm capacity from two
cogenerators totaling approximately $22 million in both 1999 and 2000. Texas
Utility Commission rules currently allow recovery of these costs through
Electric Operations' base rates for electric service and additionally authorize
the Company to charge or credit customers through a purchased power cost
recovery factor for any variation in actual purchased power costs from the cost
utilized to determine its base rates. In the event that the Texas Utility
Commission, at some future date, does not allow recovery through rates of any
amount of purchased power payments, these two firm capacity contracts contain
provisions allowing the Company to suspend or reduce payments and seek repayment
for amounts disallowed. Both of these firm capacity contracts have initial terms
ending March 31, 2005.
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(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 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
1996, savings generated for CPS' account for a partial year of joint operations
were approximately $14 million. In 1997 and 1998, savings generated for CPS'
account for a full year of operation were approximately $22 million and $14
million, respectively.
(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, 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 a refund of $5 million to an ANR
affiliate. 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:
Minimum Lease Commitments at December 31, 1998 (1)
(Millions of Dollars)
1999.................................................... $ 20
2000.................................................... 16
2001.................................................... 15
2002.................................................... 11
2003.................................................... 10
2004 and beyond......................................... 66
---------
Total......................................... $ 138
---------
- ----------
(1) Principally consisting of rental agreements for building space and data
processing equipment and vehicles (including major work equipment).
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. Resources does not expect to lease additional property under
this lease agreement.
Total rental expense for all Resources' leases was approximately $25
million in 1998. Total rental expense for all leases in 1997 since the
Acquisition Date was approximately $15 million.
(f) Letters of Credit.
At December 31, 1998, the Company and Resources had letters of credit
incidental with their ordinary business operations totaling approximately $34
million under which they are obligated to reimburse drawings, if any.
(g) Indemnity Provisions.
At December 31, 1998, Resources had a $5.8 million accounting reserve on
the Company's Consolidated Balance Sheet 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.
(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.
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23
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 judgement to that effect from a court in
Galveston County, Texas. Based on this judgement 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 case will have a material adverse effect on the Company's
financial condition, liquidity or results of operations.
From time to time the Company and its subsidiaries have received notices
from regulatory authorities or others regarding their status as potential PRPs
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 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 operation or cash flows.
(i) Other.
Electric Operations' service area is heavily dependent on oil, gas, refined
products, petrochemicals and related businesses. Significant adverse events
affecting these industries would negatively affect the revenues of the Company.
The Company and Resources are 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 and Resources' 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, against the Company and Houston Industries
Finance Inc. (formerly a wholly owned subsidiary of the Company) citing
underpayment of municipal franchise fees. The plaintiffs claim, among other
things, that from 1957 to the present, franchise fees should have been paid on
sales taxes collected by Electric Operations on receipts from sales to other
utilities and on receipts from services as well as sales of electricity.
Plaintiffs advance their claims notwithstanding their failure to notice such
claims over the previous four decades. Because all of the franchise ordinances
affecting Electric Operations expressly impose fees only on receipts from sales
of electricity for consumption within a city, the Company regards plaintiffs'
allegations as spurious and is vigorously contesting the matter. The plaintiffs'
pleadings assert that their damages exceed $250 million. The 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 remain pending. Although the Company
believes the claims to be without merit, the Company cannot at this time
estimate a range of possible loss, if any, from the lawsuit, nor can any
assurance be given as to its ultimate outcome.
(16) SUBSEQUENT EVENTS
(a) Foreign Currency Devaluation.
In January 1999, the Brazilian real was devalued and allowed to float
against other major currencies. The Company expects to take a charge against
first quarter earnings as a result of the Brazilian devaluation. The charge will
reflect the Company's proportionate share of the impact of the devaluation on
foreign denominated debt of Brazilian corporations in which the Company holds an
equity interest. The amount of the charge will not be known until the end of the
first quarter.
At December 31, 1998, one U.S. dollar could be exchanged for 1.21 Brazilian
reais. Using the exchange rate of 2.06 reais/dollar in effect at the end of
February, and the average exchange rate in effect since the end of the year, the
Company estimates that its share of the after-tax charge that would be recorded
by the Brazilian companies in which it owns an interest would be approximately
$125 million.
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COMPANY FIRST QUARTER 10-Q NOTES
(8) COMPANY/RESOURCES OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED
DEBENTURES OF THE COMPANY/RESOURCES
(a) Company.
In the first quarter of 1999, the Company, through the use of a
Delaware statutory business trust (REI Trust I), registered $500 million of
trust preferred securities and related junior subordinated debt securities. In
February 1999, REI Trust I issued $375 million of preferred securities to the
public and $11.6 million of common securities to the Company. The preferred
securities have a distribution rate of 7.20% payable quarterly in arrears, a
stated liquidation amount of $25 per preferred security and must be redeemed by
March 2048. REI Trust I used the proceeds to purchase $386.6 million aggregate
principal amount of subordinated debentures (REI Debentures) from the Company
having an interest rate and maturity date that correspond to the distribution
rate and mandatory redemption date of the preferred securities. The Company used
the proceeds from the sale of the REI Debentures for general corporate purposes,
including the repayment of short-term debt. The Company accounts for REI Trust I
as a wholly owned consolidated subsidiary. The REI Debentures are the trust's
sole asset and its entire operations. The Company has fully and unconditionally
guaranteed, on a subordinated basis, all of REI Trust I's obligations with
respect to the preferred securities. The preferred securities are mandatorily
redeemable upon the repayment of the REI Debentures at their stated maturity or
earlier redemption. Subject to certain limitations, the Company has the option
of deferring payments of interest on the REI Debentures. During any period of
deferral or event of default, the Company may not pay dividends on its capital
stock. Under the registration statement, $125 million of these securities remain
available for issuance. The issuance of all securities registered by the Company
and its affiliates is subject to market and other conditions.
For information regarding $250 million of preferred securities and $100
million of capital securities previously issued by statutory business trusts
formed by the Company, see Note 9(a) of the Company 10-K Notes. The sole asset
of each trust consists of junior subordinated debentures of the Company having
interest rates and maturity dates corresponding to each issue of preferred or
capital securities, and the principal amounts corresponding to the common and
preferred or capital securities issued by such trust.
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(9) LONG-TERM DEBT AND SHORT-TERM FINANCING
(a) Company.
(i) Consolidated Debt.
The Company's consolidated long-term and short-term debt outstanding is
summarized in the following table.
MARCH 31, 1999 DECEMBER 31, 1998
------------------------------- -------------------------------
LONG-TERM CURRENT LONG-TERM CURRENT
------------- ------------- ------------- -------------
(IN MILLIONS)
Short-Term Borrowings (1):
Commercial Paper............................ $ 1,436 $ 1,360
Lines of Credit............................. 150
Resources Receivables Facility.............. 300 300
Notes Payable............................... 2 3
------------- ------------- ------------- -------------
Total Short-Term Borrowings................... 1,738 1,813
------------- ------------- ------------- -------------
Long-Term Debt - net:
ACES $ 2,681 $ 2,350
Debentures (2)(3)........................... 1,476 1,482
First Mortgage Bonds (2).................... 1,716 150 1,866 170
Pollution Control Bonds..................... 581 581
Resources Medium-Term Notes (3)............. 176 178
Notes Payable (3)........................... 330 224 330 226
Capital Leases.............................. 14 1 14 1
------------- ------------- ------------- -------------
Total Long-Term Debt.......................... 6,974 375 6,801 397
------------- ------------- ------------- -------------
Total Long-Term and Short-Term Debt......... $ 6,974 $ 2,113 $ 6,801 $ 2,210
============= ============= ============= =============
- ----------
(1) Includes amounts due within one year of the date noted.
(2) Includes unamortized discount related to debentures of approximately
$0.5 million at March 31, 1999 and $1 million at December 31, 1998 and
unamortized premium related to debentures of approximately $17 million
at March 31, 1999 and December 31, 1998, respectively. The unamortized
discount related to first mortgage bonds was approximately $10 million
at March 31, 1999 and $10 million at December 31, 1998.
(3) Includes unamortized premium related to fair value adjustments of
approximately $17.6 million and $18.1 million for debentures at March
31, 1999 and December 31, 1998, respectively. The unamortized premium
for Resources long-term notes was approximately $11 million and $12
million at March 31, 1999 and December 31, 1998, respectively. The
unamortized premium for long-term and current notes payable was
approximately $3 million and $2 million at March 31, 1999 and $3
million each at December 31, 1998, respectively.
Consolidated maturities of long-term debt and sinking fund requirements
for the Company (including Resources) are approximately $222 million for the
remainder of 1999.
(ii) Financing Developments.
At March 31, 1999, a financing subsidiary of the Company had $1.293
billion in commercial paper borrowings supported by a $1.644 billion revolving
credit facility. At March 31, 1999, the weighted average interest rate of these
commercial paper borrowings was 5.12%.
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On March 2, 1999, another financing subsidiary of the Company terminated a
credit agreement under which it had borrowed $150 million. Funds for the
repayment of the loan were indirectly obtained from the issuance of commercial
paper by a separate financing subsidiary. For additional information regarding
the Company's and its subsidiaries' financings, see Note 8(c) and (d) of the
Company 10-K Notes.
In February 1999, the Company repaid at maturity $25.4 million and
$145.1 million of its Series A medium-term notes with interest rates of 9.85%
and 9.80%, respectively.
(11) ACQUISITIONS
On March 29, 1999, the Company and one of its subsidiaries, N.V.
Energieproduktiebedrijf UNA, a Dutch electric generating company (UNA), and the
shareholders of UNA entered into an agreement providing for the initial
acquisition of 40% of the capital stock of UNA by a subsidiary of the Company.
The purchase price for the initial 40% interest is Dutch guilders (NLG) 1.6
billion (U.S. $840 million). The purchase price for the remaining 60% of UNA is
approximately NLG 2.7 billion (U.S. $1.4 billion) and is expected to be paid no
later than December 31, 2006. Depending on the timing of regulatory approvals
and other conditions, the acquisition of the remaining interest could occur
significantly earlier than 2006.
All purchase price obligations are denominated in Dutch guilders. The
amounts shown above are subject to adjustment and assume a conversion rate of
NLG 1.88 per U.S. Dollar. It is anticipated that the closing of the initial 40%
interest will occur in June 1999, subject to receipt of various Dutch regulatory
approvals and the satisfaction of other closing conditions.
UNA is one of four large Dutch generators with approximately 3,400
megawatts of generating capacity, representing nearly 20% of the Dutch market.
It operates a mix of gas, coal and cogeneration plants in the Amsterdam and
Utrecht areas.
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COMPANY SECOND QUARTER 10-Q
(2) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC
GENERATION OPERATIONS
In June 1999, Texas adopted the Texas Electric Choice Plan
(Legislation) that substantially amends the regulatory structure governing
electric utilities in order to allow retail competition beginning on January 1,
2002. In preparation for that competition, the Company will make significant
changes in the electric utility operations it conducts through Reliant Energy
HL&P. In addition, the Legislation requires the Public Utility Commission of
Texas (Texas PUC) 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 their present
levels. The Legislation provides for utilities to recover 100 percent of 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 PUC. Retail electric providers will
not own or operate generation assets and their sales rates will not be subject
to traditional cost-of-service regulation. Retail electric providers affiliated
with the Company may compete statewide for these sales, but rates they charge
within the electric utility's traditional service territory are subject to
certain limitations at the outset of retail choice, as described below. The
Texas PUC will prescribe regulations governing quality, reliability and other
aspects of service from retail electric providers.
Unbundling. By January 1, 2002, electric utilities in Texas such as
Reliant Energy HL&P will restructure their businesses in order to separate power
generation, transmission and distribution and retail activities into different
units. Under the Legislation, Reliant Energy HL&P is required to submit a plan
to accomplish that separation to the Texas PUC by January 10, 2000. 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 percent 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 PUC determines that at
least 40 percent 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 percent 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 percent in the power
region. The Legislation also creates a program mandating air emissions
reductions for non-permitted generating facilities. The Company anticipates that
costs associated with this obligation will be recoverable through the stranded
cost recovery mechanisms contained in the Legislation.
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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 percent 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 PUC determines
that 40 percent 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
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
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 from 1999 until January 2002,
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 regulatory assets and for 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.
Accounting. Historically, the Company has applied the accounting
policies established in SFAS No. 71. For a discussion of the Company's
accounting policies under SFAS No. 71, see Note 1(c) of the Company 10-K Notes.
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,
"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), 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
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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.
The Company has evaluated the recovery of its generation related
regulatory assets and liabilities. Because the Legislation provides for the
issuance of securitization bonds up to the amount of generation related
regulatory assets at December 31, 1998 and because these bonds will be amortized
through non-bypassable charges to transmission and distribution customers, the
Company believes these amounts are probable of full recovery. If events were to
occur that made the recovery of certain of these 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 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.
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 cash flows
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 its $4.5 billion electric generation assets (prior to the impairment loss)
was impaired as of June 30, 1999. Of such amounts, $745 million relate to the
South Texas Project Electric Generating Station 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 recoverable
impaired plant costs. This new regulatory asset will be amortized as it is
recovered.
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 $797 million pre-tax 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 PUC. 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
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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, the passage of time during the transition
period and the economic lives of the plants. If events occur that make the
recovery of the regulatory asset 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 remaining
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 June 30, 1999 (including the
impairment loss discussed above) and December 31, 1998.
TRANSMISSION CONSOLIDATED
AND GENERAL ELECTRIC PLANT IN
GENERATION DISTRIBUTION AND INTANGIBLE SERVICE
---------- ------------ -------------- ------------------
(IN MILLIONS)
June 30, 1999:
Original cost ............................ $ 8,920 $ 4,349 $ 970 $ 14,239
Accumulated depreciation .................. 4,904 1,270 210 6,384
Property, plant and equipment - net(1) .... 4,016 3,079 760 7,855
December 31, 1998:
Original cost ............................. $ 8,843 $ 4,196 $ 930 $ 13,969
Accumulated depreciation .................. 3,822 1,276 207 5,305
Property, plant and equipment - net(1) .... 5,021 2,920 723 8,664
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(1) Includes non-utility generation facilities of $354 million at June 30, 1999
and $338 million at December 31, 1998 and international distribution
facilities of $25 million at June 30, 1999 and $19 million at December 31,
1998.
In order to reduce potential exposure to stranded costs related to
generation assets, Reliant Energy HL&P redirected $102 million and $195 million
of depreciation in the six months ended June 30, 1999 and year ended December
31, 1998, respectively, from transmission, distribution and general plant assets
to generation assets. Such redirection is in accordance with the Company's
transition to competition plan, approved by the Texas PUC (Transition Plan). See
Note 3(b) of the Company 10-K Notes. The cumulative amount of redirected
depreciation of $297 million is an embedded regulatory asset included in
transmission and distribution and general plant and equipment balances.
The Company reviewed its long-term purchase power contracts and fuel
contracts for potential loss in accordance with SFAS No. 5, "Accounting for
Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory
Pricing." Based on projections of future market prices for wholesale
electricity, the analysis indicated no loss recognition is appropriate at this
time.
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Other Accounting Policy Changes. As a result of discontinuing SFAS No.
71, other accounting policies related to the Company's electric generation plant
have been changed effective July 1, 1999. Allowance for funds used during
construction will no longer be accrued on generation related construction
projects. Instead, interest will be capitalized on these projects in accordance
with SFAS No. 34, "Capitalization of Interest Cost."
In accordance with SFAS No. 71, Reliant Energy HL&P deferred the
premiums and expenses that arose when long term debt was redeemed and amortized
these costs over the life of the new debt. When no new debt was issued to
refinance the retired debt, these costs were amortized over the remaining life
of the retired debt. Effective July 1, 1999, costs resulting from the retirement
of debt attributable to the generation operations of Reliant Energy HL&P will be
recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt."
The economic lives of Reliant Energy HL&P's generation plant and
equipment will be reassessed and prospective depreciation rates may be revised
due to changing economic circumstances as a result of the Legislation.
(7) TIME WARNER SECURITIES INVESTMENT
As of June 30, 1999, the Company owned 11 million shares of Time Warner
Inc. (Time Warner) convertible preferred stock (TW Preferred). On July 6, 1999,
the Company converted its TW Preferred into 45.8 million shares of Time Warner
common stock (TW Common). Accordingly, the Company will no longer receive the
quarterly pre-tax dividend of $10.3 million that was paid on the TW Preferred,
but is expected to receive a quarterly pre-tax dividend on the TW Common of
approximately $2.1 million (based on current dividend levels).
In 1997, in order to monetize a portion of the cash value of its
investment in Time Warner, the Company sold 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES). 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
By issuing the ACES, the Company effectively eliminated the economic
exposure of its investment in Time Warner 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. The closing price per share of TW Common on June 30, 1999 was
$72.625.
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 the second quarter and first half
of 1999 a non-cash, unrealized accounting loss of $69 million and
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$400 million, respectively (which resulted in an after-tax earnings reduction of
$44 million, or $0.16 per share, and $260 million, or $0.91 per share,
respectively); this correlates to the $83 million and $484 million unrecorded
unrealized gain related to the increase in the market value of TW Common during
the second quarter and first half of 1999. The Company believes the cumulative
unrealized loss for the ACES of $1.7 billion is more than economically hedged by
the approximately $2.3 billion unrecorded unrealized gain at June 30, 1999,
relating to the increase in market value of the TW Common from the Company's
cost.
Upon conversion, the Company recorded an increase in its investment in
TW Common of $2.3 billion, which represents the increase in market value of TW
Common over the Company's cost for the TW Preferred. In addition, the Company
recognized an increase of $1.5 billion in other comprehensive income, which
represents the change in market price of TW Common, net of related deferred
taxes. Upon the sale or other disposition of the TW Common, the Company is
expected to record a gain equal to the amount realized on the sale or
disposition less the original cost of the TW Preferred. As a result of the
conversion, the Company will now record changes in the market price of the TW
Common and the related changes in the market value of the ACES as a component of
stockholders' equity and other comprehensive income.
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